CLSA Coal Report

Coal outlook

Commodity analysis

Coal prices will remain hot

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Hard coking coal Semi-soft Thermal(US$/t)

Source: Company announcements, Bloomberg, CLSA Asia-Pacific Markets

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Ian Roper [email protected] (86) 2120205806

Yingxiang Zhao (86) 2120205805

For the latest news and views on the resources sector, see our weekly Asia Underground bulletin.

18 November 2010

Global Materials

For our latest views on the resources sector, see Ian’s weekly Asia Rocks commodities analysis

www.clsa.com

Craving for coal We expect thermal-coal prices to remain above US$100/tonne in nominal terms from now on while coking coal should hold above US$200/tonne until 2014. Despite slowing Chinese coal consumption, domestic supply will struggle to increase amid escalating safety and regulatory costs as well as mine depletion. The Chinese renminbi’s appreciation should make coal imports increasingly attractive. Meanwhile, India adds further upside to seaborne demand for thermal and coking coal as its economy grows.

Thermal coal - US$100 to eternity We forecast China’s import dependency for thermal coal to rise from 7% in 2010 to

13%, or 255 million tonnes, by 2015. Indian domestic coal output will also struggle to meet demand growth from the

country’s power sector, driving imports to 200 million tonnes in 15CL. Supply growth is mostly from Australia once infrastructure expansions come

through, but in the short term, Indonesia will supply most of the thermal coal.

Coking coal - Premiums to widen Hard coking-coal prices should stay above US$200/tonne until 14CL as the market sees

a widening structural deficit. Semi-soft coal discounts will widen from 27% now to 37%. The shift towards larger blast furnaces for steelmaking in China and India should keep

demand for hard coking coal growing at a faster pace than headline steel production. Australian supply will lose market share to new players Mongolia and Mozambique.

Demand drivers - China and India China and India combined account for 90% of demand growth for thermal imports,

driven by commissioning of new thermal power generation in India. The two countries also account for 77% of the increase in coking-coal consumption. Despite environmental trends against thermal generation, demand growth in

emerging markets should more than offset moves to cleaner fuels in the OECD.

Swing supply factors - Costs and infrastructure Cost inflation in China is the main driver of our price forecasts, having jumped 30%

since 2008 amid the increasing safety and regulatory focus, and mine depletion. With 25% of China’s coal transported from the north to the south, the rising renminbi

should make imports increasingly attractive for southern steel mills and power plants. Australian coal exports continue to wait for the completion of infrastructure

developments, but should double by 15CL. Indonesia will account for much of the growth in thermal-coal supply until 2012, while

Mongolia drives short-term coking-coal supply.

http://www.clsa.com/member/reports/452601818.pdf

Coal outlook

2 [email protected] 18 November 2010

Contents

Executive summary ............................................................................ 3

Thermal coal - US$100 to eternity...................................................... 4

Coking coal - Premiums to widen ..................................................... 16

Demand drivers - China and India .................................................... 29

Swing supply factors - Costs and infrastructure............................... 46

Appendices

1: Data tables......................................................................................86

2: Technical terms................................................................................88

3: Long-run Chinese steel .....................................................................91

4: Indian thermal demand.....................................................................95

5: Chinese power demand................................................................... 102

6: Global coking-coal supply by company .............................................. 122

All prices quoted herein are as at close of business 10 November 2010, unless otherwise stated

Our global materials team Andrew Driscoll, Head of Resources Research Hong Kong (852) 26008528 [email protected] Abhijeet Naik Mumbai (91) 2266505060 [email protected] Angus Graham Seoul (82) 23978429 [email protected] Ashish Gupta USA (1) 2122617724 [email protected] Chee Wei Loong Kuala Lumpur (60) 320567874 [email protected] Chesca Bugia Manila (63) 28604012 [email protected] Claire Park Seoul (82) 23978496 [email protected] Daniel Meng Hong Kong (852) 26008355 [email protected] David Lipner USA (1) 2124085724 [email protected] David Lipschitz USA (1) 2124085627 [email protected] Derek Ovington Singapore (65) 64167847 [email protected] Geoff Boyd Singapore (65) 64167853 [email protected] Hayden Bairstow Sydney (61) 285714261 [email protected] Hernan Ladeuix Hong Kong (65) 64167834 [email protected] Ian Roper Shanghai (86) 2120205806 [email protected] James Stewart Sydney (61) 285714265 [email protected] Jeremie Capron Tokyo (81) 345805291 [email protected] Makoto Kurosawa Tokyo (81) 345805284 [email protected] Mark Connelly USA (1) 2122613970 [email protected] Michael Evans Sydney (61) 285714263 [email protected] Morten Paulsen Tokyo (81) 345805770 [email protected] Narongpand Lisahapanya Bangkok (66) 22574636 [email protected] Penn Bowers Tokyo (81) 45805324 [email protected] Rajesh Panjwani Hong Kong (852) 26008271 [email protected] Rania Rahmundita Jakarta (62) 2125548834 [email protected] Richard Leung Hong Kong (852) 26008058 [email protected] Sarina Lesmina Jakarta (62) 2125548820 [email protected] Scott Laprise Beijing (86) 1059652126 [email protected] Somshankar Sinha Mumbai (91) 2266505071 [email protected] Tay Her Lim Taipei (886) 223268161 [email protected] Terry Meensook Bangkok (66) 22574633 [email protected] YingXiang Zhao Shanghai (86) 2120205805 [email protected]

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Executive summary Coal outlook

18 November 2010 [email protected] 3

Craving for coal We project thermal-coal prices to remain above US$100/tonne in nominal terms from this point. The recent surge in China’s coal imports will not reverse, as domestic production growth is constrained by quality, environmental and logistics issues. Some 56% of China’s coal consumption is in the central, southern and eastern regions, which produce only 33% of supply. Thus, almost a quarter of China’s coal has to be transported from the north to the south, in many cases over 1,000km by road but mostly around the coast by ocean vessels.

China’s coal production costs have risen 30% since 2008 amid the increasing focus on safety and regulatory burdens. Environmental issues such as water shortages in the northern mining areas, lack of high-quality coal, and reserve depletion should all contribute to higher costs and make supply growth increasingly difficult. Additionally, renminbi appreciation will make US dollar-based imports increasingly attractive for consumers on the southern coast.

We forecast China’s import dependency to rise from 7% in 2010 to 13% of thermal-coal consumption, or 255 million tonnes, by 2015. Thermal generation capacity in India is rising faster than domestic coal supply, and this will require imports to rise to 200 million tonnes by 15CL. With such strong demand drivers and cost inflation, we do not expect thermal-coal prices to see much mean reversion over time.

We expect prices for hard coking coal (HCC) to remain above US$200/tonne for the next four years. Structural shifts towards larger blast furnaces for steelmaking in China and India should keep demand for HCC growing at a faster pace than headline steel production. On the domestic supply side, China will struggle to meet demand growth from its steel industry due to rising costs and reserve depletion, thus the country will become increasingly reliant on imports.

Existing suppliers have little in the way of capacity additions planned for the next few years, which will allow new producers to gain market share. Mozambique will see first export cargoes next year, while Mongolia will triple its exports over the next four years, and has potential for significantly more supply subject to infrastructure costs.

While there is enough growth in total coking-coal supply to meet demand from steel makers, there is not enough high-quality HCC, and we see a widening structural supply deficit. Price premiums will continue to widen, with semi-soft coking coal declining to a 37% discount from 27% now.

Price upside in the short term, and staying strong in the long term

(US$/t, nominal) 2009 10CL 11CL 12CL 13CL 14CL 15CL

Thermal coal BM 85 92 105 110 107 101 101

Thermal coal spot - 98 109 112 107 101 101

Qinhuangdao contract (Rmb)¹ 540 570 610 640 672 700 669

Qinhuangdao spot (Rmb)¹ 599 745 760 760 725 700 669

Hard coking coal 171 191 210 230 200 200 167

Semi-soft coking coal 123 139 137 161 136 130 106

Pulverized coal injection coal - 150 168 184 160 160 126

Shanxi coking coal 744 835 875 920 780 780 781

¹ 5,500kcal coal, including VAT. Note: All prices are calendar year averages. Source: McCloskey, CCTD, CLSA Asia-Pacific Markets

Thermal coal prices will remain above US$100/t

due to Chinese cost appreciation

Price premiums will widen as hard coking coal sees

increasing shortage

Coal prices have a very bullish price profile

India and China combined account for 90% of

demand growth

Coking-coal consumption will rise ahead of steel

demand due to structural factors

China’s production-cost increase is the main

driver for imports

Traditional suppliers expanding only slowly

Section 1: Thermal coal - US$100 to eternity Coal outlook


Thermal coal - US$100 to eternity We expect thermal-coal prices to remain above US$100/tonne in nominal terms from now on. The recent surge in China’s coal imports will not reverse, as domestic coal production growth is constrained by logistics bottlenecks, an increasing focus on safety and environmental issues such as water shortages in the northern mining areas. Additionally, higher cost inflation than the general economy and renminbi appreciation will combine to make US dollar-based imports increasingly attractive for consumers on the south and east coast. We forecast China’s import dependency to approach 13% of thermal-coal consumption, or 255 million tonnes, by 2015. Unlike most commodities, we do not expect thermal-coal prices to see much mean reversion over time.

Figure 1

Thermal-coal-price forecasts (nominal)

(US$/t) 2009 10CL 11CL 12CL 13CL 14CL 15CL

Thermal coal BM 85 92 105 110 107 101 101

Thermal coal Spot - 98 109 112 107 101 101

Qinhuangdao contract (Rmb)¹ 540 570 610 640 672 700 669

Qinhuangdao spot (Rmb)¹ 599 745 760 760 725 700 669

¹ Qinhuangdao inc VAT. Source: CLSA Asia-Pacific Markets

Thermal-coal prices will be all about China for the next few years, but from a supply rather than a demand perspective. We believe China will be largely absent from the seaborne market as government policy is clearly trending against the export of low-value, polluting products.

The pressures on domestic mine output and costs will result in rising coal imports over time, despite a substantial slowing in China’s thermal-coal demand growth as the economy restructures away from fixed-asset investment-led expansion and additional power generation is focused more on renewables and nuclear. While downside for prices is limited by Chinese coal costs, upside potential for prices is capped by the ability of Chinese consumers to arbitrage imports. If seaborne prices rise too far, China has plenty of coal to provide a domestic supply response, although due to logistics constraints this would take a while to appear.

Chinese thermal-coal mining costs have jumped by nearly 30% over the past two years, largely due to increased safety focus and a rising regulatory burden. While such cost drivers are likely to abate in the years ahead, reserve depletion, water shortages, rising environmental awareness and renminbi appreciation will all serve to raise China’s domestic mining costs in US dollar terms and make imports increasingly attractive.

Seaborne coal demand to accelerate despite environmental trends Global consumption of seaborne-traded thermal coal has enjoyed a 6.2% Cagr over the past five years, but we forecast a slight acceleration to a 6.7% Cagr over the next five years to 2015.

Excluding China, the global traded coal market will see significant growth, led mainly by Indian imports to feed its thermal power capacity build out. Indian coal imports will experience a Cagr of more than 25% through 2015 as Coal India struggles to meet domestic demand growth, with nearly 30GW of new coal-fired generation coming into operation in the next two years.

China coal-mining cost inflation has been rapid

and will continue

Thermal coal prices won’t fall below US$100/t again

Qinhuangdao contract prices to continue rising

Thermal coal all about Chinese supply rather

than demand

Global coal import demand to accelerate

through 2015

China provides a cap and a floor to global thermal

coal prices

India will lead demand growth in power

consumption



Figure 2

Global thermal-coal seaborne import market

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

Seaborne total 693 706 736 816 861 923 983 1,069 1,123

China 45 34 92 119 130 150 180 230 255

Japan 121 126 110 121 124 122 123 123 122

Korea 67 78 84 93 93 95 97 99 101

Taiwan 58 58 54 55 56 56 57 58 58

India 33 37 47 59 80 120 145 175 200

Other Asia 51 55 49 55 57 59 62 64 67

EU27 187 185 179 184 186 184 182 180 178

Other Europe 34 38 34 35 35 35 35 35 35

Middle East & Africa 26 26 26 26 26 26 26 26 26

North America 50 49 39 44 48 49 50 51 52

South America 22 22 24 25 26 26 27 28 29

Source: Australian Bureau of Agricultural and Resource Economics (ABARE), Trade data, McCloskey, CLSA Asia-Pacific Markets

Combined, China and India will account for more than 90% of the growth in seaborne thermal-coal imports to 2015, more than countering the rising global trend of switching away from thermal generation towards other cleaner energy sources.

Supply growth led by Indonesia and Australia Indonesia and Australia account for a combined 53% of seaborne thermal-coal exports. Their share of supply should rise to 65% by 15CL as both grow their export volumes.

Figure 3

Global thermal-coal seaborne export market

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

Seaborne total 684 716 730 782 845 910 977 1,075 1,161

Indonesia 193 198 231 260 286 304 318 334 350

Australia 111 121 134 137 140 180 240 330 410

China 51 43 22 19 10 5 5 5 5

Other Asia 16 21 24 26 28 30 32 34 36

South Africa 68 68 67 66 69 70 73 77 78

Russia 85 86 91 93 98 95 95 95 95

USA 24 35 19 21 28 26 24 22 22

Colombia 65 69 63 68 76 82 85 88 90

Other 71 75 78 93 110 118 105 90 75


Indonesia has seen substantial growth in coal exports in recent years, and should provide much of supply growth to 12CL, but we expect this pace to slow as equipment shortages, rising stripping ratios and more challenging logistics for new mines make bringing on new capacity increasingly harder and more expensive, while strong domestic demand limits the share of exports.

Australian supply represents the main threat to prices in the medium and long term, as infrastructure plans in Queensland and New South Wales are now advancing on capacity of more than 600 million tonnes per annum (mtpa) by 2015, up from about 300mtpa in 2010. Should demand stumble, this capacity growth is unlikely to be underutilised given the low costs of

China and India will be the two major importers

China and India will account for 90% of

demand growth

Indonesia is a major exporter in the seaborne

thermal-coal market

Australia to double coal export capacity by 2015

Indonesia and Australia account for most of supply



Australian coal production. The success of these projects is one of the key influences on medium-term price forecasts. However, given that this supply won’t be impacting the market until at least 2012, we see upside to thermal-coal prices globally over the next two years.

Ultimately, these sustained high prices will just incentivise more infrastructure capacity to come on in places with abundant coal reserves such as Africa, but we believe the long lead times for these projects mean a significant increase in supply is not likely within the forecast period to 2015. Consequently, we see the thermal-coal seaborne market in deficit in 2011 and 2012, before rebalancing as Australian export capacity ramps up.

Figure 4

Global thermal-coal seaborne export market

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

Seaborne demand 693 706 736 816 861 923 983 1,069 1,123

Seaborne supply 684 716 729 783 845 910 977 1,075 1,161

Supply deficit 9 (10) 7 33 16 13 6 (6) (38)


Chinese cost inflation will drive the appetite for imports In assessing the long-run thermal-coal price, we have to strike a balance between coal costs in the Chinese market, which is 93% domestically sourced, and the global traded coal market balance and costs. Our belief is that China will not see significant coal exports in the future, however high the global coal price gets. Government policy is quite clearly moving away from exporting low-value, highly-polluting products, which use up their own transport and energy resources without making much return. Should global coal prices rise to an attractive level for Chinese coal traders to export, we believe the authorities would respond by hiking export taxes from their current 10% level, or furthering the use of export quotas which were a major factor in restricting exports of coke over the past decade.

Figure 5

Chinese coal trade tax changes

Thermal coal

Pre 2004 13% export rebate

Jan 2004 11% export rebate

Jan 2005 8% export rebate

Sept 2006 export rebate removed

Aug 2008 10% export tax

Source: Media reports, Ministry of Finance, CLSA Asia-Pacific Markets

According to NBS statistics in 2008, 56% of China’s coal consumption was in the central, southern and eastern regions, which produces only 33% of the coal supply. Thus, nearly 25% of China’s coal has to be transported from the north to the south, which is costly and puts great strain on China’s logistics networks.

With China absent from the global traded thermal-coal market as a supplier, the big question is at what price China will find it attractive to import coal. Given China’s (washed) thermal-coal consumption will be about two billion tonnes in 2015, and the total seaborne coal market ex-China will still be about 900mt, China’s presence or absence in the global market will be the major swing factor for coal prices.

Global seaborne demand will outpace supply

until 2014

China won’t be a big coal exporter again

China regional coal consumption and

production is unbalanced

China’s import demand will define the global coal

market balance

Potential for higher supply globally, but only

after 2015

Trade policy has moved away from

supporting exports



The seven coastal provinces in east and south China, namely Hainan, Guangxi, Guangdong, Fujian, Zhejiang, Shanghai and Jiangsu accounted for a combined 22% of total coal consumption in 2008, according to the NBS, and we estimate an even higher rate for thermal coal. Thus, we could easily envisage China’s thermal-coal imports rising to between 10% and 15% of coal consumption, but would struggle to believe it could rise much above 20% before raising cost assumptions for imports given that they will likely be getting less competitive with domestic coal the further they are moved inland.

Figure 6

Chinese import penetration

(mt) 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLCoal consumption in generation 1,367 1,450 1,616 1,702 1,796 1,891 1,943 1,998South/East coast consumption 342 363 404 426 449 473 486 500Domestic coal production 1,376 1,380 1,515 1,582 1,651 1,716 1,718 1,748Coal imports 34 92 119 130 150 180 230 255Coal exports 43 22 19 10 5 5 5 5Import penetration nationally (%) 2 6 7 8 8 10 12 13Import penetration (S/E coast) (%) 10 25 29 31 33 38 47 51

Note: Thermal-coal consumption is washed basis. Source: NBS, CLSA Asia-Pacific Markets.

To calculate the price at which China will choose to import thermal coal, we need to asses China’s domestic coal sources and associated logistics costs. Inner Mongolia is already China’s largest thermal-coal producing province, but given the provinces low quality and water shortages, growth in thermal-coal production is likely to come increasingly further west, from Xinjiang in particular. While we expect China’s economic growth to rebalance towards the centre and west over time, the bulk of China’s energy needs will remain on the eastern and southern coastal provinces.

Mining costs for thermal coal in China are quite high in relation to the rest of the world. More than 80% of China’s thermal-coal mines are underground, and on average the costs of underground mines are at least twice that for open-pit mines. The most efficient thermal mines in China have a cash mining cost as low as Rmb150/tonne, while the least efficient can be as much as Rmb200-230/tonne (prior to quality adjustments). Adding in washing costs, non-mining operating costs and rail loading fees, and the average mining cost comes in about Rmb230-240/tonne, with the highest cost mines being at Rmb280-320/tonne free on rail/truck.

Figure 7 Figure 8

Cost breakdown of middle-cost mine

Cost breakdown of high-cost mine

0

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200

300

400

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loading

Non-mingcost and railloading fee

Taxes Logistics

(Rmb/t)

0100200300400500600700

Mining,washing and

loading


Taxes Logistics

(Rmb/t)

Source: Industry sources, CLSA Asia-Pacific Markets

Infrastructure is the major cost for coal delivered to southern consumers. The cost of moving coal from Shanxi to Guangdong is currently near Rmb300/tonne while the cost to move coal from Inner Mongolia is about Rmb380/tonne.

China coal-mining costs are at the higher end of

global cost curve

Transport from Shanxi costs Rmb300/tonne

Import coal penetration can easily rise to 10-15%

Seven coastal provinces account for 22% of coal

consumption

Chinas domestic coal will come from further west

Infrastructure is the major cost for coal

delivered to southern consumers



Figure 9

Transport cost for coal from Shanxi (650km rail + ship) to Guangdong

0 50 100 150 200 250 300 350

Road to railway station

Rail loading

Rail

Port construction

Port handling

Other

Ship to Guangdong

Port unloading

(Rmb/t)

Figure 10

Transport cost from Inner Mongolia (200km road, 900km rail) to Guangdong

0 50 100 150 200 250 300 350 400


Rail loading

Rail

Port construction

Port handling

Other

Ship to Guangdong

Port unloading

(Rmb/t)


We expect these costs to come down as more rail infrastructure is put in place. The Ministry of Rail is planning capacity to carry 1.2 billion tonnes of coal from 2013 so there should be less need for more expensive trucking. Assuming all coal moves by rail, at current tariff rates that would imply a cost of about Rmb300/tonne from a generic mine in Inner Mongolia, 1,000km to Qinhuangdao and along the coast to Guangdong.

By 2015, assuming a moderate pace of real cost inflation for mining at 5% per annum in 2011/12 and 2.5% thereafter, adding the new resource tax at 4%, and allowing for some efficiency gains in logistics which more than offset inflation, we would expect the cost for Shanxi mines on a delivered Guangdong basis to be about Rmb570/tonne, or US$104/tonne, in real 2010 terms assuming a Rmb5.5/US$1 rate.

China domestic coal cost will rise in coming years

due to inflation and resource tax

As rail capacity increases, costs could come down

Main costs are rail and shipping, but additional

ones add up

Road and rail are the main cost additions for

mines in Inner Mongolia



Figure 11

Total cost (2010 terms), 2015 Shanxi mid-cost mine delivered to Guangdong

0

100

200

300

400

500

600

Mining cost Non-mining cost Taxes and othercosts

Logistics toSouthern China

(Rmb/t)


For the lower-quality mines in Inner Mongolia delivering the longer distance to Guangdong, we could easily see costs being as high as Rmb725/tonne, or US$132/tonne, in real 2010 terms.

Figure 12

Total cost (2010 terms), 2015 Inner Mongolia high-cost mine delivered to Guangdong

0

100

200

300

400

500

600

700

800

Mining cost Non-mining cost Taxes and othercosts

Logistics toSouthern China

(Rmb/t)


A good check on these costs is also the arbitrage opportunity for Mongolian thermal coal, as this could also become a significant supplier to the Chinese market once logistics are in place. An analysis of the potential for Mongolian coal exports is discussed in detail in the supply section. Briefly, our discussions with Mongolian coal companies suggest a target operating cost of US$15/tonne for raw coal, but after adjusting for low quality and washing, and transport to the Chinese border once rail capacity is in place, and currency appreciation, the free-on-board (FOB) China cost would still be US$40/tonne at best, or Rmb220/tonne at a Rmb5.5/US$1 exchange rate. Even assuming minimal border-crossing fees, such as under a free-trade agreement, the logistics costs through Inner Mongolia and on ship to Guangdong would still bring the total cost to about Rmb550/tonne, or US$100/tonne. We believe there is probably upside to the inflation, currency and tax assumptions, so the cost could potentially be another 20% higher at least.

Mongolia coal cost delivered to south China

is also above US$100

Lower-quality mines will be higher cost

China domestic coal cost from Shanxi will rise to

Rmb570/tonne

Despite logistics savings Inner Mongolian costs will

still hit Rmb725/tonne to Guangdong



The final marginal source for new coal supply in China would be from new mines in Xinjiang. These are expected to be mostly open pit, and higher quality than Inner Mongolian coal. Even with cheaper mining costs however, Xinjiang coal would still need to travel 2,000-2,500km to central/southern China, which on current rail fees would work out about Rmb300-340/tonne including loading and fees, so we would struggle to see them competing at a delivered price to the southern power plants of under Rmb550/tonne.

Given the expensive logistics for coal, and the provinces desire to add value to their raw materials, there is growing talk of more mine gate power capacity being installed, with the power being exported to other provinces rather than the coal. In principal, this sounds like a promising and logical idea, however, China’s grid already has serious issues and it will be many years before it could have the capacity to handle hundreds of gigawatt hours (GwH) worth of transmission from north to south China. Given that the distance would be 1,500-2,500km from most mines to the south coast, the cost of the power cable combined with the transmission losses would be significant. China is already reportedly planning to invest Rmb2.2tn in the power grid over the next five years, up from Rmb1.5tn over the past five years, but most of this is just to upgrade and improve the existing grid rather than provide capacity for such a significant increase in cross-province distribution. Consequently, we view the issue of mine gate power as a potential long-term risk, but it will not be enough to destroy the potential import market for thermal coal in the next decade.

It is quite apparent from our cost analysis that domestic thermal coal will struggle to be delivered into southern power plants for under US$100/tonne in 2015 (real 2010 terms). Thus we would expect to see significant import penetration into southern and eastern China from seaborne coal up to this cost level.

Figure 13

Chinese thermal coal costs, 2015

(mt) Shanxi Inner Mongolia Xinjiang MongoliaMining cost 180 275 150 100Taxes and other costs 140 150 100 130Logistics to Southern China 250 300 340 330Total cost Rmb/t 570 725 590 560Total cost US$/t 104 132 107 102Source: CLSA Asia-Pacific Markets

To net back to an FOB Newcastle equivalent price, we simply deduct the freight and Chinese port-handling costs, and make an adjustment for the higher calorific value of Australian coal, which is about 6,000Kcal compared to standard Chinese quality at 5,500Kcal. After making these adjustments, the netback would equate to about US$90/tonne FOB Newcastle in real 2010 terms in 2015. We therefore choose to set our long-run thermal-coal price at this level, which is equivalent to US$100/tonne in nominal 2015 terms.

Prices have upside in near term In terms of the interim prices, thermal-coal markets look reasonably tight for the next few years. Our market balance shows that there is a sustained supply deficit in the 2010-12 period, before large-scale infrastructure capacity expansions come through in Australia and lead to a surge in exports.

Spot coal prices have rallied strongly in the six weeks to 12 November. While the rally is reflective of the liquidity pressures and US dollar weakness that have been driving all commodities, the coal price has also been boosted by

Power transmission is hard to replace coal

transport in next decade

Spot coal price is very sensitive to weather change

Xinjiang is too far from southern consumers to

be competitive

Our market balance is very tight through 2012

Domestic coal to Guangdong does not look

viable at under US$100/tonne

Mongolia and Shanxi best placed to provide

southern power plants



expectations of a colder-than-usual winter in China and a worse-than-normal summer rainy season in Australia, both due to the La Nina weather pattern. The weather traditionally provides a very clear seasonal pattern for coal prices, with strength in 4Q and 1Q, and softness in 2Q and 3Q.

Figure 14

Thermal-coal prices have clear seasonal effect

0

40

80

120

160

200

240

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

(US$/t) 2010 2009 2008

2007 2006 2005

Source: McCloskey, CLSA Asia-Pacific Markets

Given coals sensitivity to weather impacts on both the supply and demand side, we expect there could be upside risk to spot prices over 1Q11, but there is also a danger that expectations of weather impacts are baked into current spot prices and could thus cause downside if they don’t eventuate.

With the tight market balance, we forecast thermal-coal spot prices to average US$109/tonne in 2011, up from US$98/tonne in 2010. There will be another increase in 2012 to US$112/tonne, before prices moderate towards the long run US$100/tonne level in 2015 (nominal terms) as Australian exports grow strongly and ease the market tightness.

For Chinese pricing, thermal-coal contract prices in China have never gone down, and we forecast them to rise another 7% in 2011 and continue to gain through the forecast period. The rise in prices reflect a closing of the discount to spot, as producers have been switching more tonnages away from contract towards the spot market to avoid giving away this discount, and ultimately the two prices should converge. For Chinese spot prices, they will follow a similar pattern to seaborne spot prices, but at a slightly slower pace to reflect the 4-5% pa renminbi appreciation.

Figure 15

Thermal-coal price forecasts (nominal)

(US$/t) 2009 10CL 11CL 12CL 13CL 14CL 15CLThermal coal BM 85 92 105 110 107 101 101Thermal coal Spot - 98 109 112 107 101 101QHD contract (Rmb)¹ 540 570 610 640 672 700 669QHD spot (Rmb)¹ 599 745 760 760 725 700 669Seaborne demand 736 816 861 923 983 1,069 1,123Seaborne supply 729 783 845 910 977 1,075 1,161Supply deficit 7 33 16 13 6 (6) (38)¹ QHD inc VAT. Source: CLSA Asia-Pacific Markets

Thermal-coal price will rise through 2012

There is more upside to 1Q prices due to supply

disruptions

Chinese contract prices will continue to rise

China contract price will maintain uptrend until

converges with spot price



Risks to our forecasts - upside Further policies to restrict Chinese thermal-coal output could be a major upside risk to our forecasts. The success of the policies in Shanxi may inspire similar consolidation in other provinces, though given no other province has such dispersed ownership of coal assets, the effects would be somewhat smaller. Nonetheless, this could still cut available Chinese supply below our expectations.

In Shanxi, private-mine output before consolidation accounted for about 40% of production, but post consolidation this has dropped to under 30%. Given Shanxi had a uniquely high number of private mines, we chose to examine a scenario where Chinese thermal-coal output is reduced by 3% due to further closures and consolidation of small mines around the country. On this basis, and assuming no change to the demand numbers, China’s seaborne coal imports would rise by more than 40mtpa from 2012, with an ultimate import penetration in the south coast markets of 75% by 2015.

Figure 16

Chinese import penetration - base case

(mt¹) 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

Coal consumption in generation 1,367 1,450 1,616 1,702 1,796 1,891 1,943 1,998

South/East coast consumption 301 319 347 366 377 397 398 400

Domestic coal production 1,376 1,380 1,515 1,582 1,651 1,716 1,718 1,748

Coal imports 34 92 119 130 150 180 230 255

Coal exports 43 22 19 10 5 5 5 5

Import penetration nationally (%) 2 6 7 8 8 10 12 13

Import penetration (S/E coast) (%) 11 29 34 36 40 45 58 64

Figure 17

Chinese import penetration - Production cut 5% by small mine closures

(mt¹) 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL


South/East coast consumption 301 319 347 366 377 397 398 400


Coal imports 34 92 119 157 190 221 272 297

Coal exports 43 22 19 10 5 5 5 5



Net gain in imports - - - 27 40 41 42 42

¹ refers to washed thermal-coal consumption. Source: CLSA Asia-Pacific Markets

Given that our market balance is not in deficit until 2014, these extra Chinese imports would further tighten the market and prevent prices falling back after 2012. However, we believe the upside to coal prices would be capped, as it is unlikely the Chinese authorities would prevent a supply response from large-scale efficient mines over time, especially given the increasingly attractive returns from the higher-price environment.

An additional upside risk in China could come from more stringent safety and environmental compliance requirements which raise mining costs above our forecasts. We estimate the regulatory burden over the past two years has raised mining costs by at least Rmb50/tonne. While further measures are unlikely to raise costs that much given diminishing returns, an increase of just Rmb25 could raise our long-run coal price by up to US$5/tonne. An increase in the resource tax in China above the speculated 4% level could also add around US$0.8/tonne to our long-run price for every 1% increase in the tax.

Further efforts unlikely to be as significant

as in Shanxi

China coal mines consolidation is a major

upside risk

Upside to prices capped by potential domestic

supply response

Restricted domestic supply would mean

higher imports

China mine cost may further rise due to safety

and environmental requirement and higher-

than-expected resource tax

Further cost pressure in China could come from

more regulation



Any moves by the Indonesian government to restrict coal exports could tighten the global coal market further. While these risks seem unlikely at this stage, the environmental impact of the rapid increase in production may get increasingly negative coverage in the country, leading to pressure on the government to regulate the industry more strictly.

Indonesia accounts for 20% of our supply growth to 2015, but this is heavily weighted to 2011 and 2012, when our market balance is at its tightest. If such restrictions came in the next two years, this could cause significant upside to prices, though we would then just expect Chinese imports to lessen and their domestic production to respond to the higher prices. Restrictions from 2013 or later meanwhile could lessen our expectation of prices declining after 2012.

Delays in infrastructure expansions elsewhere would provide upside to prices, with Australia being the main factor in supply growth. However, these expansions have been a long time in planning and look likely to be delivered on time. Nonetheless, a delay of six months in commissioning could cut Australian thermal exports by up to 30 million tonnes in 2012 and 2013, and even more in later years.

Indian growth could surprise to the upside. While we are already being aggressive in our import assumptions, with imports feeding over 50% of the growth in thermal-coal generation, there could even be upside to these numbers, most likely from disappointing domestic coal production growth. However, our plant-by-plant assessment suggests the bulk of coastal power plants will already be relying mostly on imports, and for imports to penetrate much inland they will be subject to similar logistics costs and constraints to the domestic supplies.

Nonetheless, a scenario where Indian coal production growth misses our forecasts by 50% would result in imports rising by 20-25mtpa through the forecast period. Such additional tightness to the market could add US$5/tonne to our price forecasts through the period.

Figure 18

Indian demand for thermal coal in power generation - base case

(mt) FY10CL FY11CL FY12CL FY13CL FY14CL FY15CLDemand 426 451 542 603 657 711Domestic supply 374 387 432 473 489 522Imports 52 64 110 132 168 189

Figure 19

Indian thermal-coal import demand - 50% reduction in domestic coal output

(mt) FY10CL FY11CL FY12CL FY13CL FY14CL FY15CLDemand 426 451 542 603 657 711Domestic supply 374 381 403 424 432 448Imports 52 71 139 180 226 263Import gain - 6 29 48 58 75Source: CLSA Asia-Pacific Markets

Faster renminbi appreciation than we expect could lift interim and long-run price forecasts as we drive our prices from the Chinese mining cost. We assume a 5% pa appreciation for the next two years, followed by 4% pa after that in our base case, giving a Rmb5.5/US$1 exchange rate by 2015. The table below shows the impact of various exchange-rate assumptions on our price forecasts.

Indian import demand could be greater than

we expect

Indonesian government could limit coal exports

Indonesia accounts for much of the supply

growth through 2012

Capacity expansion delays in Australia are a risk to

medium-term prices

If Indian coal supply growth disappoints imports would rise

Our base case expects Indian imports of 189 million tones

in 2015

If domestic supply growth disappoints, Indian imports could be an

extra 75 million tonnes

Forecast prices are very sensitive to renminbi

assumptions



Figure 20

Thermal-coal price forecasts - renminbi scenarios (nominal)

(US$/t) 2015 (Rmb) 10CL 11CL 12CL 13CL 14CL 15CLBase case 4-5%pa 5.5 92 105 110 107 101 101No appreciation 6.6 92 100 100 90 85 82Slower case 2%pa 6.0 92 102 104 99 94 92Faster case 6%pa 4.8 92 107 113 110 107 105Note: QHD inc VAT. Source: CLSA Asia-Pacific Markets

Risks to our price forecasts - downside One downside risk to our thermal-coal price forecast is the speed at which Indian thermal generators come into operation. While our forecasts allow for reasonable delays in construction and ramp ups, Indian construction projects have a poor record for delivering on time, and significant slippage in the commissioning of new plants could reduce demand for seaborne thermal coal below our expectations.

Indian coal imports account for 45% of the growth in seaborne-coal demand in our base case. If we factor in a six-month delay in the startup of all thermal capacity additions for the next five years, but still assume the same domestic thermal-coal production base, Indian imports would be on average 30mtpa lower over 2011-15, likely resulting in much lower spot thermal-coal prices, particularly for 2011 and 2012 as the market tightness we are forecasting then would be eliminated.

Figure 21

Indian demand for thermal coal in power generation - base case

(mt) FY10CL FY11CL FY12CL FY13CL FY14CL FY15CL

Demand 426 451 542 603 657 711

Domestic supply 374 387 432 473 489 522

Imports 52 64 110 132 168 189

Figure 22

Indian demand for thermal coal in power generation - six-month delay


Demand 426 440 505 573 629 680

Domestic supply 374 387 432 473 489 522

Imports 52 53 73 100 140 158

Import loss - (11) (37) (32) (28) (29)Source: CLSA Asia-Pacific Markets

A second downside risk could come from a sudden slowdown in Chinese demand growth, perhaps caused by a sharper-than-expected cooling in the economy post stimulus, or external economic shocks from a double-dip recession or re-emergence of worries over debt in the OECD. Any of these factors could provide downside to our demand forecasts. Additionally, sharply slower Chinese economic growth could lead the government to soften their efforts to restrict low-value exports and reform industries, and thus allow for greater coal supply in China.

Assessing the feed through of this scenario is rather complicated as there are so many secondary effects, but on the whole a slowdown in Chinese economic growth could reduce total coal consumption, and if inflationary pressures are reduced may make domestic production more competitive. On this basis, we could see substantial downside to spot prices in this scenario, as Chinese

A 5% pa renminbi rise in next two years and 4% pa

afterwards are assumed

Indian thermal generators could begin at a slower

pace than we expect

Imports could be 30mtpa lower if there is a 6

month delay in start up

Our base case is for Indian imports of 189 million tonnes in 2015

Imports would be cut if power generation

is delayed

Sudden slowdown in Chinese demand would

result in lower spot thermal-coal price

Chinese imports below 100mt in 2011 would

push the spot price below US$90/tonne



import demand would be significantly smaller. If Chinese imports decline below 100mtpa from 2011, we would expect spot thermal prices to drop below US$90/tonne FOB Newcastle.

As well as a slowdown in China, another risk would be a double-dip global recession, particularly in Europe. The EU still accounts for 22.5% of thermal-coal imports, while other OECD nations account for around one-third of seaborne imports. Between 2008 and 2009 coal imports in OECD countries fell by 6%, but have recovered all of this loss in 2010. While a repeat of such a sharp slowdown as seen in 2009 is unlikely, a milder recession could still knock thermal-coal demand by 3% in OECD nations, or 13-15 million tonnes. While not enough to tip the market into surplus, the feed-through effects of a double-dip recession onto emerging markets would likely cut thermal demand elsewhere as well, pushing prices back below US$100/tonne.

Milder winters and less-extreme weather impacts could be another reason for lower prices than we forecast. Thermal-coal prices have been very influenced by extreme winter storms in China in recent years, so the absence of these could mean weaker demand and improved coal supply, keeping prices lower.

Climate change and related environmental taxes could make the economics of coal-fired power generation less attractive globally, encouraging a switch to renewables, nuclear or gas to feed energy demand growth. While we already assume a gradual shift away from coal in most countries, an acceleration of this trend could lead to substantially lower coal demand than we forecast in the long run. However, this is hard to envision within the five-year forecast period, given the lead times in constructing new generating capacity, especially nuclear. Technological breakthroughs which improve the efficiency and economics of renewables could also contribute to slower coal consumption than we expect in the longer term, and thus pressure long-term coal prices.

The introduction of carbon taxes would be the main spur for reduced coal consumption. In an extreme case where these caused power consumption to fall at end users in developed countries, it is likely that thermal-coal generation would bear the brunt of the cut in power production. Again, we believe this is more of a longer-term risk however, and is unlikely to be significant in emerging markets where we see most of the demand growth for thermal coal, especially given that their thermal generation comes from newer, more environmentally-friendly plants.

Cheap gas is another threat to thermal-coal consumption, but again this is more of a medium-term threat given the lead time to develop new power generation. The USA is looking to shale gas as a possible source of alternative energy, but there are still environmental question marks over its operation and thus how significant a power supply it could become. If the technology is proven and shale gas becomes a popular energy source globally, this could reduce coal consumption further in the long run. In the shorter term, cheap gas prices in the USA could provide upside to US coal exports, as coal miners look to alternative markets if home demand is weaker than forecast.

Less-extreme weather could soften coal-price

volatility

OECD double-dip recession would also push

spot prices below US$100/tonne

Cheap gas is a long-term threat to coal consumption

Climate-change issues and carbon taxes could make coal-fired power

generation less attractive

Development of renewable energy and

improved energy efficiency may contribute

to slower coal consumption

Carbon taxes would pressure coal consumption

Section 2: Coking coal - Premiums to widen Coal outlook


Coking coal - Premiums to widen We expect prices for hard coking coal (HCC) to remain above US$200/tonne for the next four years. Structural shifts towards larger blast furnaces for steelmaking in China and India will keep demand for HCC growing at a faster pace than headline steel production growth rates. On the supply side, China will struggle to meet domestic demand growth, and thus become increasingly reliant on imports. While there is enough growth in total coking-coal supply to meet this demand, there is not enough high-quality HCC, meaning that price premiums will continue to widen.

Figure 23

Coking-coal price forecasts


Hard coking coal 171 191 210 230 200 200 167


PCI Coal - 150 168 184 160 160 126

Shanxi coking coal¹ 744 835 875 920 780 780 781

¹ Shanxi coking coal is near HCC grade, but unwashed and ex VAT. Source: CLSA Asia-Pacific Markets

As with thermal coal, the driver of the coking-coal market will be the pace of cost inflation in China, and the consequent balance between imports and domestic supply. Additionally, the pricing dynamics between different product grades will change as the steel industry continues to upgrade steel production in favour of larger furnaces, while global output of the highest-quality coking coals struggles to expand.

For all coking coal we forecast demand growth of 42% in the five years to 2015. HCC will grow at a faster pace due to the structural demand drivers such as industry trends towards larger furnaces and Indian steel mills upgrading their facilities, which we outline later in this report. Total HCC demand over the next five years will rise 55%, or a Cagr of 9%. China and India will account for a combined 80% of the growth in HCC consumption.

Figure 24

Global coking-coal seaborne import market

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

Seaborne total 229 233 217 272 299 325 348 370 387

China 6 7 35 45 62 80 89 97 107

Japan 65 65 52 63 61 58 59 59 58

Korea 21 22 19 22 26 28 29 30 31

Taiwan 8 8 6 8 8 8 8 9 9

India 24 28 29 35 38 42 49 59 61

Other Asia 1 2 2 2 2 2 2 2 2

EU27 67 67 48 63 64 65 68 70 70

Other Europe 7 8 5 7 6 7 8 8 9


North America 8 7 5 7 7 7 8 8 8

South America 17 16 13 17 19 22 23 24 26

Source: Australian Bureau of Agricultural and Resource Economics (ABARE), Trade data, McCloskey, Industry sources, CLSA Asia Pacific Markets

Global coking-coal demand will rise over

40% in next five years

China domestic cost inflation is the driver of the coking-coal market

HCC prices to stay above US$200/tonne until 2014

Tighter market for HCC will widen price premium

Coking-coal demand will enjoy a 7.3% Cagr

through 2015



Figure 25

Global hard coking-coal seaborne import market

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

Seaborne total 153 137 166 186 216 238 257 279 288

China 5 5 26 35 52 66 73 79 86

Japan 36 37 31 34 35 33 33 33 33

Korea 12 12 12 13 15 17 17 18 19

Taiwan 5 5 4 5 5 5 5 5 5

India 19 22 24 28 34 40 48 57 59

Other Asia 1 1 1 1 1 1 1 1 1

EU27 49 36 45 45 48 48 50 55 52

Other Europe 6 4 5 5 4 4 4 5 5


North America 6 4 6 6 6 6 6 7 7

South America 11 10 11 11 13 15 15 16 17

Source: Australian Bureau of Agricultural and Resource Economics (ABARE), Trade data, McCloskey, Industry sources, CLSA Asia Pacific Markets

We believe China’s steel demand still has a considerable way to grow over the next seven or eight years, before peaking later this decade as the economy reaches upper middle-income status. We assume steel production in China will rise at a 7.3% Cagr over the next five years. Our reasoning is outlined in the demand section, and explained in more detail in Appendix 3.

While steel production rose from 129 million tonnes in 2000 to more than 503 million tonnes in 2008, China remained largely self sufficient in coking coal, importing only 6.9 million tonnes in 2008. China also managed to sustain coke exports over that time, with exports peaking at 15 million tonnes in 2007, and declining to 12.1 million tonnes in 2008. However, in 2009 the combination of reduced mine output in Shanxi due to safety related consolidation issues, and the increased availability of coking coal on the seaborne market as world steel production collapsed, meant China began to import coking coal in large quantities. We expect China’s import requirement for coking coal to continue to expand as domestic coking-coal supply is struggling to grow due to grade depletion and significant cost inflation.

Figure 26

Chinese coking-coal supply

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

Crude steel prod 489 503 568 630 665 716 772 835 897

Pig iron prod 477 469 544 609 641 686 746 807 863

CC consumption 334 328 381 426 448 480 522 565 604

Domestic CC 350 339 347 382 387 401 434 469 498

Imported CC 6 7 35 45 62 80 89 97 107

Exported CC¹ 22 18 1 1 1 1 1 1 1

Import share (%) 2 2 9 11 14 17 17 17 18

¹ Exports include coke. Source: NBS, CLSA Asia Pacific Markets

China’s domestic production of coking coal recovered to new highs in 2010, exceeding 2007 levels. For the next five years we forecast Chinese coking-coal production to grow at a 5.5% pa rate, compared to the 7.3% growth in steel production. Consequently, imports will be required to rise from 11% of consumption to 18% by 2015.

HCC demand will grow 55% through 2015

China coking-coal import requirement will expand as

domestic supply constrained

China’s steel demand has good long-term prospects, with a 7.3% Cagr to 2015

Import share of consumption will rise to

18% by 2015

China’s domestic coking coal to only grow 5.5% pa



Indian coking-coal imports will be driven by two factors. Steel production growth in the country will rise 40% over the next five years. Steel demand in the country will rise at a faster pace, but production will lag demand growth due to the difficulties in constructing steel mills in most states. A further boost for imported coking coal will come from existing steel-production facilities upgrading their furnaces. India currently has one of the highest average coke rates in the world, due to the small scale and older average age of its steel-making capacity. As existing producers upgrade their facilities, they will increasingly demand higher-grade coking coals, which can only be supplied from the seaborne market. This is the reason we have Indian HCC imports rising by 112% over the next five years, and our reasoning is explained in more detail in the demand section of this report.

Supply remains constrained HCC supply growth on the seaborne market will be mainly led by four regions, Australia, North America, Mongolia and Mozambique. Australia already supplies over half of the seaborne HCC market, mostly from the Bowen Basin in Queensland, and this level of concentration is one of the main reasons why prices have been so volatile, as weather or logistics issues in this one region have such a wide reaching effect on the market balance.

Figure 27

Global coking-coal seaborne export market

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

Seaborne total 220 231 226 271 309 338 362 382 395

Australia 139 139 139 154 171 179 181 185 187

Mongolia 3 4 6 13 19 25 33 41 43

China 3 2 1 1 1 1 1 1 1

Other Asia 2 2 2 3 4 7 8 10 12

Canada 26 27 24 27 32 36 39 40 40

US (ex Canada) 26 35 32 48 55 59 62 62 62

Mozambique 0 0 0 0 0 3 5 10 16

CIS 11 13 13 15 17 19 23 24 25

Other 11 9 8 10 11 10 10 10 10

Apparent deficit 9 2 (9) 1 (10) (13) (14) (12) (8)

Figure 28

Global HCC seaborne export market

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

Seaborne total 144 155 148 185 211 234 248 263 273

Australia 76 77 75 86 95 100 100 103 103

Mongolia 2 2 3 8 11 14 18 22 23

China 1 1 1 0 0 0 0 0 0

Other Asia 3 3 3 4 5 8 9 11 13

Canada 23 24 22 24 28 32 35 36 36

US (ex Canada) 26 35 32 48 55 61 62 62 62

Mozambique 0 0 0 0 0 3 5 10 16

CIS 6 7 7 8 9 10 12 12 13

Other 8 6 6 7 8 7 7 7 7

Apparent deficit 8 (18) 18 1 5 4 9 16 15Source: Australian Bureau of Agricultural and Resource Economics (ABARE), Trade data, McCloskey, Industry sources, CLSA Asia Pacific Markets

Indian demand driven by steel expansions and

furnace upgrades

Australia is the major player in the

seaborne coking- coal market

Rising structural deficit for HCC as supply growth is lacking

Mongolia and Mozambique will see the fastest growth in supply



In terms of industry concentration by company, BHPB/Mitsubishi alliance (BMA) controls more than 55% of Australia’s HCC exports, and 33% of the total seaborne market. As seaborne coking-coal supply increases over the next five years, BMA will see its market share decline to 19% by 2015, though its share of Australian exports will be sustained at 55%.

Mongolian exports have been growing strongly in the past couple of years, and recently replaced Australia as China’s largest source of coking-coal imports. Despite being next to China however, logistics costs are not cheap given the lack of rail capacity in the region, while on a quality basis only around half of Mongolia’s coking-coal volumes are truly HCC as outlined later in the supply section of this report.

Mozambique has been a major focal point of investment in coking coal, and will see first shipments from Vale’s Moatize mine in late 2011, with Riversdale soon to follow from its Benga mine. However, despite the large-scale, high-quality reserve base, logistics constraints will limit the production ramp-up for the next few years.

Elsewhere, North American producers have seen a surge in exports this year, but are unlikely to see much more growth in the years ahead due to logistics constraints, while in Russia coking-coal exports from the east coast ports will see a significant jump as the Mechels Elga project ramps up.

While we see total seaborne coking-coal supply having a 7.8% Cagr and HCC having an 8% Cagr over 2011-15, we view demand as being more than strong enough to absorb this supply. In fact there is a growing structural deficit of HCC over our forecast time period, which will have to be reflected in widening price premiums.

Figure 29

Coking-coal price forecasts (nominal)


Hard coking coal 171 191 210 230 200 200 167


PCI coal - 150 168 184 160 160 126

Shanxi coking coal¹ 835 875 920 770 750 804 835

Total CC demand 217 272 299 325 348 370 387

Total CC supply 226 271 309 338 362 382 395

CC supply deficit (9) 1 (10) (13) (14) (12) (8)

HCC demand 166 186 216 238 257 279 288

HCC supply 148 185 211 234 248 263 273

HCC deficit 18 1 5 4 9 16 15

¹Shanxi coal is unwashed, ex VAT. Source: CLSA Asia-Pacific Markets

Price forecasts - Chinese cost inflation the key To assess the long-run price of coking coal we look toward the global cost curve, and particularly the costs for new suppliers. As the total seaborne market for coking coal will see significant demand growth, the coking-coal price will need to rise to a level which incentivises new supply. Currently, the highest cost traditional large-scale coking-coal suppliers, on a CFR China basis, are the North American mines at more than US$120/tonne, while some of the smaller producers are over US$150/tonne.

Mongolian exports will see the most growth

Global demand for HCC will grow faster than supply

BMA will see declining market share

Prices premiums will widen reflecting HCC

supply deficit

North American suppliers are highest cost in the

seaborne market

Mozambique will be a major new supplier

North America and Russia contribute some growth



The two alternatives to seaborne supplies for Chinese steel mills are domestic coking coal, which comes mainly from Shanxi, or overland imports from Mongolia. It is the costs of these producers which will set China’s appetite for seaborne imports and hence the long-run seaborne price for coking coals.

Shanxi provides the vast majority of China’s coking-coal output. The consolidation efforts in Shanxi are the main factor causing a rise in China’s imports for coking coal, especially hard coking coal.

Figure 30 Figure 31

China coal output by type

Shanxi coal output by type

Thermal coal63%

Coking coal37%

Thermal coal

49.8%

Coking coal

50.2%

Source: Sxcoal, CLSA Asia-Pacific Markets

The consolidation process and drives to improve mine safety in Shanxi have seen many small mines there close. The number of mines in the province has been reduced from more than 4,500 to only 1,063, of which 136 are SOEs and 927 are local mines, of which 30% of those are truly private and the rest have mixed ownership. Output from small and medium mines has declined from more than 30 million tonnes per month in 2007 to only 22 million tonnes per month in 1H10. The minimum size for the mines post consolidation is about 300ktpa, and most of the still operating small mines are relatively new ones which were built to a decent safety standard.

Figure 32

Shanxi coal mine consolidation

0

200

400

600

800

1,000

1,200

1,400

2003 2004 2005 2006 2007 2008 postconsolidation

(mtpa)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000(No.)Capacity (LHS) No. of mines

Source: Fenwei, CLSA Asia-Pacific Markets

Recent visits to Shanxi give the impression that mine output will recover in the coming years, albeit at rather a slow pace. The SOE consolidators complain that with so many small scale, often illegal, mine shafts scattered around the now consolidated large deposits, the new owners are struggling to

Shanxi is the major source of China domestic

coking-coal supply

Numbers of mines in Shanxi dropped greatly

due to consolidation

Some deposits have been ruined by illegal mines, so output will recover slowly

China can alternatively source from Mongolia

Shanxi has the greatest share of coking coal

Production will recover post consolidation



come up with viable mine plans. In many cases the remaining deposit looks like Swiss cheese with multiple holes through the best bits, so the SOE owners are unlikely to even try to restart production from some deposits as it looks unsafe to do so.

In terms of Chinese costs, these have already jumped by over 30% in the past two years as the rising focus on safety and environmental issues have combined with a need for mines to go deeper and deeper underground into more complex geology as resources are increasingly consumed. Some mines now extend so deep and wide that it takes miners up to two hours to get to the active coal face.

Cash costs of production in Shanxi are still low compared to current prices. The pretax cost for mining, washing and loading coking coal is between Rmb350-400/tonne for most mines in the province, with SOE mine costs generally higher than the smaller ones as the only existing small ones now are newer, more efficient ones. We expect structural mining issues will cause real mining costs to inflate at least 5% a year.

Figure 33

Shanxi coking coal total cost delivered to Shanghai, 2010

0 100 200 300 400 500 600 700 800

Mining cost

Overheads

Taxes and fees


Railway loading

Railway

Railway construction fund

Port handling

Other

Ship to Guangdong

Port unloading

(Rmb/t)

Figure 34

Shanxi high cost mine delivered to Shanghai, 2010

0 200 400 600 800 1,000

Mining cost

Overheads

Taxes and fees


Railway loading

Railway


Port handling

Other

Ship to Guangdong

Port unloading

Port unloading

(Rmb/t)

Source: CLSA Asia-Pacific Markets

Shanxi costs are low compared to current prices

Safety issues have contributed to a 30% jump in mining costs

Current cost for Shanxi coal to costal steel mills is

around US$120/tonne

High cost mines mainly suffer higher mining cost

and logistics charges



In terms of total costs, logistics can easily add up to more than Rmb250/tonne from Shanxi to a coastal steel mill (see the China infrastructure section, page 61). Royalties add another Rmb12/tonne currently, but under the likely resource tax reforms could well exceed Rmb35/tonne. There are many other taxes payable for mines in Shanxi, including environmental fees, safety fund and mineral resource compensation fund contributions among others. After adding in other non-mining costs such as sales and management of Rmb60-70/tonne the total cost base for an average Shanxi coking-coal mine is easily above Rmb750/tonne or US$115/tonne at current exchange rates. The highest-cost mines with washing yields below 60%, which by some industry estimates account for 20% of production, have a cost of over Rmb900/tonne delivered to a coastal steel mill, or US$135/tonne.

Assuming the resource tax is switched to a 4% base, this could increase all coking-coal costs by Rmb20-25/tonne. Over time, Chinese costs for labour, safety equipment and general inputs will be growing well ahead of basic global inflation levels, and the renminbi will continue to appreciate against the dollar at a rate of 4-5% pa according to our economists.

In total, if we add the tax changes and then inflate Chinese costs in real US dollar terms by 10% pa through 2013, then 5% pa after that, this puts the average mine costs in 2010 US dollar terms at US$158/tonne delivered to a coastal mill, with the highest cost mines up to US$185/tonne. We believe there would be some scope for efficiency gains and cost reductions in the logistics chain as capacity improves, but even so it looks certain that the highest cost Chinese HCC supply will be comfortably above a US$150/tonne cost level delivered to a coastal Chinese steel mill.

Some 55% of the cost increase is driven by renminbi appreciation, with further contributions from mine cost appreciation, general inflation and taxes.

Figure 35

Coking-coal cost drivers, 2010 to 2015 change

0

5

10

15

20

25

30

35

40

45

50

Mining costs Taxes General inflation Rmb appreciation

(US$/t)


Mongolia the main alternative to domestic supply We use the cost of Mongolian coking coal as a check against our implied price on the seaborne market. If Mongolian coking coal was substantially lower cost, we would expect mines there to massively increase export volumes over time, and displace the high-cost suppliers in the seaborne market.

Highest-cost mines above US$135/tonne

Rising renminbi accounts for 55% of

cost appreciation

Inflation and renminbi to drive cost appreciation

Resource tax could add cost pressure

Mining costs are low, but logistics are high



While mining costs in Mongolia are generally low, the combination of VIU (value-in-use) discounts for quality, and logistics costs to move coal to the Chinese border, then through China’s largest coal production base to the coast and on to steel mills on the east coast, mean that its total cost is not significantly below our expectation for long-run seaborne prices even after assuming decent rail logistics are put in place.

The lowest total cost for Mongolian coking coal is currently around US$150/tonne delivered to Shanghai (this is explained in more detail in the Mongolian section of the supply chapter). Costs in Mongolia could develop in two ways. We could see cost improvements if miners are able to build the desired infrastructure, such as rail and wash plants, and a free-trade agreement which lowers border crossing costs. Alternatively, we could see costs continue to inflate, especially given the considerable investment planned for the remote areas of Mongolia, which could lead to significant input cost inflation, in addition to currency pressures.

Figure 36

Mongolia coking-coal total cost delivered to Shanghai, 2010

0 20 40 60 80 100 120 140 160

Mining

Truck 1

Border fees

Truck 2

Washing

Truck 3

Rail to port

Port fees

Shipping

Port fees

(US$/t)

Source: CRR, CLSA Asia-Pacific Markets

One caveat of overly relying on the Mongolian mining costs is the currency impact. Given the proposed investments in coal, copper and other mining in Mongolia, we would expect the currency to appreciate substantially over the next decade. Indeed between March 2009 and November 2010 the Mongolian tugrik has already appreciated by 25%, from 240 per US$1 to 192 per US$1.

Being a relatively small country, the authorities could try to limit this appreciation by pegging the tugrik to the renminbi, rouble or US dollar. Given the strong sense of independence in the country it is doubtful they would peg to the renminbi despite the economic links, so the US dollar would be the most likely option. However, this would bring negative consequences elsewhere in the economy, and while other small countries seem able to cope with pegs, we believe appreciation would still be the best option over time.

Under the optimal cost scenario, such as that planned by MCC building its own wash plants and rail, combined with moderate currency appreciation and a free-trade deal, we could see delivered HCC costs in 2015 from Mongolia to Shanghai at US$130/tonne in 2010 real terms.

Mongolia currency may appreciate substantially

over the next decade

Current Mongolia coking coal cost to Shanghai is around US$150/tonne

Mongolian coal could be a swing supplier to China

Current Mongolia coking-coal cost breakdown

Limited options to prevent currency

appreciation

Cost Mongolia coking coal to Shanghai could reduce to

US$130/tonne in 2015



Figure 37

Mongolia coking coal delivered cost to Shanghai, 2015 optimal

0 20 40 60 80 100 120 140

Mining

Washing

Rail 1

Border

Rail 2

Port fees

Shipping

Port fees

(US$/t)


We believe a more likely scenario of moderately higher cost inflation and currency appreciation will result in costs above US$155/tonne in real 2010 terms for the most efficient producers with captive infrastructure.

Figure 38

Mongolia coking-coal transportation cost to Shanghai, 2015 likely

0 20 40 60 80 100 120 140 160 180

Mining

Washing

Rail 1

Border

Rail 2

Port fees

Shipping

Port fees

(US$/t)


The total change from 2010 would not be significant, as efficiency gains from improved logistics and trade terms would largely offset the cost increases and currency appreciation.

Figure 39

Mongolia coking-coal transportation cost change, 2015 likely versus 2010

0 10 20 30 40 50 60

RMB appreciation

Tugrit Appreciation

Input cost inflation

Trade agreement savings

Logistics savings

Net cost increase

(US$/t)


Cost more likely to be US$155/tonne in 2015

Optimal scenario involves improved infrastructure

and free trade deal

Cost of US$155/tonne for those with captive

infrastructure; higher for smaller players

Logistics savings are the main hope for lower costs



However, if producers are unable to change the current logistics structure, and currency appreciation is more aggressive, we could see costs spiralling above US$215/tonne delivered to Shanghai, making Mongolian coking coal uneconomic for all but the northern Chinese steel mills.

Figure 40

Mongolia coking-coal transportation cost to Shanghai, high cost 2015

0 50 100 150 200 250

Mining

Truck 1

Border fees

Truck 2

Washing

Truck 3

Rail to port

Port fees

Shipping

Port fees

(US$/t)


In conclusion, we choose to set our long run HCC price from 2015 at US$150/tonne FOB Australia in real 2010 terms. The analysis above shows that neither Shanxi nor Mongolian coal is economically feasible for south/east coastal steel mills at a delivered price of US$150/tonne, and even US$160/tonne will still be a struggle. Moreover, we believe the risks to costs are to the upside, especially given the Mongolian currency issue. A US$150/tonne FOB Australia price would equate to about US$160/tonne delivered to a Chinese steel mill, after allowing US$8/tonne for long-run freight and US$2/tonne for port handling, which appears more than competitive with Shanxi and Mongolian coal. Australian HCC will also benefit from a quality premium for most grades.

Interim prices - Pressure remains in the near term For short-term price forecasts, we see increasing upside to prices in 1Q11. Spot HCC prices have averaged US$215/tonne mid-way through 4Q, and this is amid a weak steel market in China. Additionally, rains in Queensland have already put additional pressures on the market, though to some degree this is priced in and should cyclones not occur could actually be a downside risk to prices. We look for benchmark HCC prices to rise to US$215/tonne in 1Q, and average US$210/tonne for the year as a whole as we expect Chinese steel demand to be depressed post stimulus.

Beyond 2011, we do not see significant supply growth to pressure prices lower before 2013, and assuming our Indian demand profile, perhaps before 2015. This would imply prices can continue to see a comfortable margin ahead of costs for a few years yet, before returning to long-run prices. With a recovery in global steel markets into 2012, we see coking-coal prices rising further.

The price dynamics between different coking coals is another variable in our forecasts. 4Q10 prices saw a significant disconnect in prices for various qualities, with HCC prices declining 8% QoQ, while semi-soft prices fell 18% on average.

Costs above US$215/tonne if no improvement in

infrastructure

These costs would be uneconomic

We set our long-run HCC price at

US$155/tonne FOB Australia

We see increasing upside to prices in the short term

Prices will peak in 2012

Price premiums will widen



How wide can price differentials get? As HCC premiums rise, we would expect to see steelmakers look to using more PCI in their burden, and reduce HCC usage to the minimum which is structurally required to hold up the burden (see Appendix 2 for technical details). However, quality PCI coals are also not plentiful in supply, so if too many steelmakers chase these, its price could increase closer to HCC prices. Additionally, steelmakers have been put off from using more PCI as this product has seen the most pricing volatility in recent years.

We forecast the semi-soft coking-coal price discount versus premium HCC to widen from the 27% average in 2010 to a 36% discount by 2015. Any greater discount than this and the semi-soft price will become close enough to thermal coal to not warrant producer’s efforts in processing. Given the market tightness and increasing attraction of switching to PCI, we forecast PCI discounts to narrow to 20% from HCC through 2014, before settling at a long-run discount roughly 25% below HCC prices.

Pricing dynamics There has been a structural shift in pricing. Traditionally, prices were set on an annual benchmark based on the Japanese fiscal year (April to March). Prices for hard coking coal were agreed and then the lower-value coking coals were priced according to the hard coking-coal price. The presence of more frequent price setting reduces the “gaming” of the system by both buyers and sellers, and should lead to reduced volatility in prices and shipments. One impact of the switch is that the liquidity in the spot market has dried up, given that producers are able to get prices more in line with market conditions every quarter so are happy to continue shipping on a contract basis. The spot market has thus been reduced to only a few cargoes a month to India and China. Overall the pricing system doesn’t change the structural underlying dynamics of demand and supply, so has little impact on our price view.

Key risks to our price forecasts - Upside Chinese steel production has slowed sharply in 2H10 on the back of energy intensity cuts. While we believe the low steel prices indicate that underlying demand is entering a softer period post stimulus which could last until 2H11, it is possible that steel production recovers faster than we expect. Strong PMI data, buoyant consumer sales for autos and appliances, and high housing starts this year boosted by social housing could all contribute to steel production being higher than the 5.5% we expect. If this happens, coking-coal prices could be sharply higher than we forecast.

In a scenario where Chinese steel production achieves a Cagr of 8.5% for the next five years, compared to our base case of 7.3%, China’s coking-coal imports in 2015 would be 26 million tonnes higher than our base case, with HCC 22 million tonnes higher, assuming that the higher prices incentivise a domestic supply response which fulfils half of the additional demand growth.

Figure 41

Chinese steel growth sensitivity

(US$/t) 2009 10CL 11CL 12CL 13CL 14CL 15CLChina CSP base case 568 630 665 716 772 835 897Coking-coal imports 35 45 62 80 89 97 107HCC imports 26 35 52 66 73 79 86HCC prices 171 191 210 230 200 200 167China CSP high case 568 630 684 742 805 874 948Coking-coal imports 35 45 72 93 105 117 133HCC imports 26 35 61 77 86 98 108HCC prices 171 191 210 250 220 220 167Note: Shanxi coking coal is near HCC grade, but unwashed and ex VAT. Source: CLSA Asia-Pacific Markets

PCI discount to HCC will narrow while semi-soft coking-coal discount to

HCC will widen

Faster production recovery in 2011 will put

upside risk on price

Steel mills will try to switch further to PCI

from HCC

New pricing system will lessen volatility, but no change to price outlook

China’s import of coking coal would have to rise

Higher Chinese coking-coal imports would

raise prices



While we expect a subdued 2011 for steel production in China, we also look for a weak year in the rest of the world too given our economics team’s pessimistic view on OECD macro. If OECD macro and hence steel demand are stronger, this could again add tightness to the seaborne market.

With Queensland supplying almost 50% of seaborne HCC, severe weather impacts in the region could reduce supply, sending prices sharply higher. Heavy rains in 1Q08 were the key driver for spot HCC prices reaching US$400/tonne, and a repeat of such supply disruptions could see a repeat of those price levels. However, expectations for disruption are already high given the La Nina weather cycle is expected to cause a higher-than-normal number of cyclones this year, so there is also potential that a quieter than forecast season could add downside to prices.

Further tightening of mine safety issues in China, possibly caused by another serious accident in Shanxi, could reduce Chinese domestic coking-coal supply further. We are forecasting China’s coking-coal production growth recovering to a 5.5% Cagr over the next five years, after struggling since 2007. If this was cut to 2.5%, it could provide a need for an additional 70 million tonnes of imports by 2015.

Figure 42

Chinese coking-coal supply - Base case

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLCrude steel prod 489 503 568 630 665 716 772 835 897Pig iron prod 477 469 544 609 641 686 746 807 863CC consumption 334 328 381 382 387 401 434 469 498Domestic CC 350 339 347 45 62 80 89 97 107Imported CC 6 7 35 45 57 70 83 94 107Exported CC¹ 22 18 1 1 1 1 1 1 1Import share (%) 2 2 9 11 14 17 17 17 18

Figure 43

Chinese coking-coal supply - A 2.5% domestic production Cagr

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLCrude steel prod 489 503 568 630 665 716 772 835 897Pig iron prod 477 469 544 609 641 686 746 807 863CC consumption 334 328 381 426 448 480 522 565 604Domestic CC 350 339 347 382 392 401 411 422 432Imported CC 6 7 35 45 55 78 110 142 171Exported CC¹ 22 18 1 1 1 1 1 1 1Import share (%) 2 2 9 11 12 16 21 25 28¹ Exports include coke. Source: NBS, CLSA Asia Pacific Markets

Greater renminbi appreciation is more of a risk to prices in the medium and longer term. We are already assuming a 4-5% pa appreciation for the next few years, but a sudden one-off revaluation could boost China’s purchasing power and appetite for imports ahead of more expensive domestic supply, adding upside risk to prices.

Figure 44

HCC price forecasts - Renminbi scenarios (nominal)

(US$/t) 2015 (Rmb) 10CL 11CL 12CL 13CL 14CL 15CLBase case 4-5% pa 5.5 191 210 230 200 200 167No appreciation 6.6 191 200 210 175 165 137Slower case 2% pa 6.0 191 206 218 184 180 152Faster case 6% pa 4.8 191 212 235 208 212 175Source: CLSA Asia-Pacific Markets

Weather disturbance in Australia is another

upside risk

Further tightening of mine safety and greater renminbi

appreciation can drive up domestic Chinese costs

Our base case is for 5.5% pa domestic supply growth

If supply only grows 2.5%, imports would rise

70 million tonnes by 2015

Disruption to exports from Queensland could send

prices sharply higher

Prices are very sensitive to renminbi assumptions

Long-run prices may be under US$140/tonne if

there is no renminbi rise



Key risks to our price forecasts - Downside Slower Chinese steel demand growth than we forecast would be a serious downside risk to prices. While our 5.5% growth in Chinese steel production in 2011 is already below consensus, a sharper than expected cooling in the economy post stimulus, or external economic shocks from a double dip or re-emergence of worries over debt in the OECD, could all provide downside to our demand forecasts.

If we look at a scenario where China sees zero steel production growth in 2011, followed by a 7% growth from then on, demand for imported coking coal would be about 20mtpa lower over the forecast period assuming slightly less domestic coking-coal production as well. This would eliminate the tightness in the HCC market, and likely keep prices comfortably below the US$200/tonne level for the forecast period.

Figure 45

Chinese steel growth sensitivity

(US$/t) 2009 10CL 11CL 12CL 13CL 14CL 15CLChina CSP base case 568 630 665 716 772 835 897Coking-coal imports 35 45 62 80 89 97 107HCC imports 26 35 52 66 73 79 86HCC prices 171 191 210 230 200 200 167China CSP low case 568 630 630 674 721 772 826Coking-coal imports 35 45 42 60 66 71 85HCC imports 26 35 37 46 53 57 66HCC prices 171 191 190 180 170 170 167

Note: Shanxi coking coal is near HCC grade, but unwashed and ex VAT. Source: CLSA Asia-Pacific Markets

Closer cooperation between Mongolia and China to lower Mongolian delivered costs and increase their export volumes would be a threat to our medium and long run price forecasts. Border fees currently represent US$20/tonne for Mongolian exports, while the argument over Chinese and Russian gauge rail within Mongolia is proving a serious delay to miners infrastructure hopes. If the two countries were to cooperate more closely, perhaps signing a free trade agreement, this could substantially reduce Mongolian coal costs on a delivered China basis, and thus allow them to raise their export volumes and lower long-run prices nearer to a US$130-140/tonne level.

Alternative steel and coke-making technologies which allow for use of lower grade coking coals are limited at the moment, and unlikely to become a significant factor in the medium term. Technological developments are likely to focus on alternative iron-making technologies which look to utilise lower grade raw materials, as well as improve environmental efficiencies, such as Finex and HIsmelt. However, both of these have struggled to role out beyond small scale demonstration plants as the existing steel-making technology is well known and in China, relatively cheap to construct. However, the adoption over time, or additional technological breakthroughs, could provide downside to our price views, especially regarding the premiums for HCC.

The emergence of more steel scrap in China is a serious long-term threat to coking-coal demand. As China is an emerging economy, it has a very small scrap pool, but this will expand rapidly later this decade, thus negating the need for virgin iron units. If scrap emerges as China’s steel production peaks, demand for coking coal in China could turn negative year by year, but this is unlikely to happen until 2018-20. For more details on the potential threat from scrap, please see Appendix 3 on China’s long-term steel industry outlook.

Scrap will limit China’s coking-coal demand in the

long term

Sharper post-stimulus slowdown in China can

eliminate market tightness

Mongolia coal cost can be reduced through better cooperation with China

Zero steel production growth in China in 2011

would push HCC prices below US$200/tonne

Prices would be sharply lower if steel production

in China disappoints

Technological developments could harm long-term demand growth

Section 3: Demand drivers - China and India Coal outlook


Demand drivers - China and India The demand drivers for coking and thermal coal are very different. For this report, we will analyse the demand by product, and sub-categorise by region. Thermal coal is probably the only commodity which is not going to be driven by demand growth in China over the next few years, as it is the take off in thermal generation in India which will be driving this market from a gross demand perspective. Coking coal will also see a demand boost from India’s development, but that remains more of a longer-term forecast. Coking coal, particularly hard coking coal, will remain a China story for the near future.

Just under one-third of the world’s primary energy demands are fed by coal, and coal was used to produce 41% of the world’s electricity in 2009. The main consumers of coal from the seaborne traded market are countries which lack in domestic coal supply, namely Japan, Korea, Taiwan, the UK, and countries which have plenty of coal themselves but not enough to meet all their needs, such as India and Germany.

Thermal coal - Accelerating China - Powering down, but imports will take share For thermal coal, China will remain an optional importer, with southern power plants choosing to import if seaborne prices are cheap, but easily switching back to domestic supply if prices rise too far.

Figure 46

China’s coal consumption by sector

Fertilizer(incl other coal-based

chemicals)4%

Cement(incl other construction

materials like glass)14%

Steel16%

Other¹17%

Powergeneration

49%

Total coal consumption in 2009 = 3.2bn tonnes

¹ Used by households, steam locomotives and other end-users. Source: CCTD, CRR

China’s thermal-coal imports have risen from 13 million tonnes in 2007 to 39 million tonnes in 2009, and an annualised 60 million tonnes over 1H10. On a net basis, China has switched from being an exporter of 32 million tonnes in 2007 to net imports of 20 million tonnes in 2009. Thermal coal accounts for about 30% of China’s coal imports.

Coking coal remains a China story while thermal coal

will be benefit from India

Half of coal consumed by power sector in China

Coal supplied 40% of the world’s electricity in 2009

Economics of local supply will drive Chinese thermal

coal imports

Thermal coal accounts for 30% of China’s imports



Figure 47

China thermal-coal imports and exports

(40,000)

(30,000)

(20,000)

(10,000)

0

10,000

20,000

30,000

40,000

50,000

2007 2008 2009 2010 Jan-Sep

Thermal coal import Thermal coal export Net import('000 t)

Source: CCTD, CLSA Asia-Pacific Markets

Unlike coking-coal demand, which we expect to see solid growth in the years ahead, for thermal coal we expect demand to slow significantly, as the economy rebalances away from investment driven growth which has spurred the development of heavy industry and hence power consumption. As explained in detail in Appendix 5, from our September 2010 China’s energy binge report, China’s economy will be moving away from investment-led growth, and this will translate into substantially lower rates of power consumption, as witnessed in the development of Japan and Korea.

The three challenges China faces are reducing the energy consumption per unit of economic output, changing the mix of that energy towards greener energy and reducing the environmental pollution from energy being consumed. Achieving these objectives involves economic, legal, political and social reforms, but as they are achieved the pace of demand growth for coal will slow substantially.

With China’s energy consumption growth slowing amid economic restructuring, and an increased focus on new power supply from gas, nuclear and renewable sources, China’s thermal-coal consumption growth looks likely to be subdued in the years ahead. Our forecasts for China’s energy consumption growth over the next 10 years are for a Cagr of 4.8%, while for thermal-coal generation we only expect a Cagr of 3.1%.

China’s overall energy mix is set for a big change with a fairly sharp drop in the share of coal and a rise in the share of natural gas, oil and renewable energy capacity as is evident from Figures 48 and 49.

Wind power will experience the highest increase in capacity share among all available technologies, rising from 3% in 2010 to 12% in 2020 and 18% in 2030. While wind will have the highest incremental share in capacity, the technology with the biggest portion in actual power generated will be nuclear. This is because of the much higher utilisation levels for nuclear (more than 80%) compared with less than 25% for wind and solar. We expect nuclear to account for 7.9% of power generated by 2020 and 15.1% by 2030.

Power consumption in China will slow as the

economy rebalances

Three challenges are energy intensity, energy

mix and pollution

China’s energy mix in for a big change

Wind power will experience the biggest

rise in terms of capacity

Thermal-coal demand will grow slower than total

power demand

China used to be an exporter of coal,

but no longer




Figure 48

China’s total energy consumption trend by fuel/technology

0

1,000

2,000

3,000

4,000

5,000

6,000

2003 2006 2009 2012 2015 2018 2021 2024 2027 2030

Hydro, nuclear, wind, solar, others

Natural gas

Oil

Coal

(m tonnes)

Figure 49

Share of various fuels, technologies in China’s long-term energy mix

0

20

40

60

80

100

2003 2006 2009 2012 2015 2018 2021 2024 2027 2030

Coal Oil Natural gas Hydro, nuclear, wind, solar, others(%)

Source: CEIC, CLSA Asia Pacific Markets

While the near-term demand for coal (2011-13) is relatively robust (also supported by potential implementation of Nitrogen Oxide control norms) at about 5%, we expect a sharp slowdown from 2014 due to a steep decline in coal-fired power generation as well as a slowdown in production of steel, aluminium and cement, among others. We expect thermal-coal demand to slow to about 2-3% in 2014-16 before slowing further to about 1% or less in the following years.

Figure 50 Figure 51 Figure 52

China’s mix of power generated

2010

Hydro15.6%

Nuclear1.7%

Wind1.3%

Gas2.7%

WTE0.1% Other

0.9%

Coal77.7%

2020

Hydro15%

Nuclear8%

Wind6%

Gas4%

Solar1% Other

2%

WTE1%

Coal63%

2030

Wind9%

Hydro14%

Coal51%

Other3%

WTE1%

Solar2%Gas

5%

Nuclear15%

Source: CEIC, CLSA Asia-Pacific Markets

CLSA’s energy mix forecast

Coal will experience a sharp slowdown in

demand around 2014

Share of wind, solar, nuclear and gas to rise at

the cost of coal



Coal will remain the king - But one with shrinking turf Despite the increase in share of non-coal power capacity, power generation through coal-based capacity will remain the largest in China in 2020 as well as 2030. However, the share of power generated from coal will shrink considerably over this period. We expect the share of coal in total power capacity to come down from 71% in 2009 to 52% in 2020 and 42% in 2030. While the portion of coal-fired capacity in total generation should come down from 78% in 2010 to 63% in 2020 and 51% in 2030.

In the past decade, thermal power (primarily coal) accounted for 74% of net new installed capacity, hydropower’s share was 20%, wind 5% and nuclear had 1% share. In the next decade, we expect the share of coal to shrink to less than half at 36%, wind at 24%, hydro 14%, nuclear 9% and gas 5%. During the decade ending 2030, wind’s share in net new installations rises to 35%, followed by nuclear at 22%, hydro 14%, solar 10%, gas 7%, biomass 6% and waste to energy at 3%.

Overall, thermal and coal-power capacity additions are already down from their peak of about 96GW in 2006. However, capacity additions have picked up again in 2009 after a sharp fall in 2008. Based on the capacity already under construction, we anticipate 2010 additions to be at similar levels and a gradual decline in 2011. However, we expect capacity additions to start a steady decline from 2012.

We have assumed that the shutdown of old and inefficient capacity continues at about 10GW per annum beyond 2010. This number could be higher if the government is stricter, allowing gross capacity additions to grow at a faster pace than we are forecasting. The shutdown is likely to accelerate from 2020 as the capacity China added in the mid-1990s approaches its retirement life of close to 25 years. Towards the late-2020s, China’s coal and thermal power capacity additions are likely to turn negative as the plants added by China during its boom period after 2002 start to reach retirement age.

Figure 53

Gross and net thermal power capacity additions forecasts

(20,000)

0

20,000

40,000

60,000

80,000

100,000

120,000

2005

2006

2007

2008

2009

10CL

11CL

12CL

13CL

14CL

15CL

16CL

17CL

18CL

19CL

20CL

21CL

22CL

23CL

24CL

25CL

26CL

27CL

28CL

29CL

30CL

(MW) Net thermal additions Gross thermal additions

Source: CEC, CLSA Asia-Pacific Markets

Coal will still be the most important energy resource

Thermal capacity additions already down

from their peak

Thermal capacity additions set to decline

Capacity shutdown could be higher than

our estimates

Thermal capacity additions will lessen in

favour of renewables



Apart from a higher share of renewable capacity and a slowdown in energy intensive industry, improving energy efficiency will be another driver for the slowdown in coal demand. We expect gradual efficiency improvements in energy intensity for most industries.

Figure 54

Coal demand growth rate

(%)

(5)

0

5

10

15

20

2000 2005 2010 2015 2020 2025 2030


China is also experimenting with coal to liquid technologies to reduce its dependence on imported oil. However, this increases China’s dependence on coal and hence is not an ideal solution to the oil shortage. The success of these technologies will depend on oil prices and future development in technologies which can make the conversion processes cleaner and more efficient.

As China still has plenty of thermal-coal reserves to exploit, it should theoretically have no problem meeting its own demand growth with domestic supply. However, we believe cost pressures and tighter domestic policies on safety and environmental issues will restrict China’s domestic coal output while still encouraging imports. China will import a significant volume of coal should the global price become cheaper than its domestic cost base as happened in 2008. That is largely dependent on China’s domestic inflation, logistics network costs, and renminbi appreciation, and is discussed in the supply section of this report.

Figure 55

Chinese import penetration

(mt) 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLCoal consumption in generation 1,367 1,450 1,616 1,702 1,796 1,891 1,943 1,998South/East coast consumption 342 363 404 426 449 473 486 500Domestic coal production 1,376 1,380 1,515 1,582 1,651 1,716 1,718 1,748Coal imports 34 92 119 130 150 180 230 255Coal exports 43 22 19 10 5 5 5 5Import penetration nationally (%) 2 6 7 8 8 10 12 13Import penetration (S/E coast) (%) 10 25 29 31 33 38 47 51

Note: Thermal-coal consumption is washed basis. Source: NBS, CLSA Asia-Pacific Markets

India - Powering up Demand for thermal coal in India will grow very strongly over the next few years, as a recent spate of investment in thermal generation plants come into operation. Nearly 75% of Indian thermal-coal consumption is by power utilities, with the remainder mostly from heavy industrial plants.

Improving energy efficiency lowers

coal demand

Coal to liquids unlikely to become significant

Indian demand will be led by significant power

capacity additions

Rising coal imports despite the slowdown in

demand growth

Improving energy efficiency will also cut

coal demand growth

China to see rising import penetration for thermal coal



Figure 56

India power consumption by sector

Power - Utility75%

Other7%Cement

6%

Power - Captive8%

Steel (non-coking)4%

Figure 57

India’s power demand basket - End-user breakdown

Domestic27%

Commercial8%

Irrigation22%

Industry35%

Others8%

Source: CEA, CLSA Asia-Pacific Markets

We expect power demand to grow more or less at the same rate as GDP, as India has a substantially smaller share of industrial output to GDP than China. Industry is the largest part of the pie in overall power consumption in the country. However the higher (and growing) share of services in GDP (which is less energy-intensive than industry and agriculture) could lead to a continued drop in elasticity of power demand. On the positive side, increasing industrial activity, electrification of villages and rising power supply over the next couple of years should all create additional demand for power.

To meet this strong demand, generating capacity is already seeing massive investment, spurred by reforms earlier in the decade. In 2003, India passed the Electricity Act, which ushered in a new era of reforms, leading to a massive increase in new investment especially from the private sector. Capacity addition over FY10-13 should exceed that in the past 10 years with US$50bn being invested in the sector. In total India is likely to add about 50GW of total power capacity over the next three years.

Non industrial sectors consume two-thirds of

Indian power

We expect demand to grow at the

same rate as GDP

Power consumption in industry is relatively low

We expect 50GW addition in the 11th plan



Figure 58

Electricity-demand and real-GDP growth

0

2

4

6

8

10

12

FY94

FY95

FY96

FY97

FY98

FY99

FY00

FY01

FY02

FY03

FY04

FY05

FY06

FY07

FY08

FY09

Demand Real GDPAverage demand Average GDP

(%)

Figure 59

Capacity-addition targets

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

FY93

FY94

FY95

FY96

FY97

FY98

FY99

FY00

FY01

FY02

FY03

FY04

FY05

FY06

FY07

FY08

FY09

FY10F

FY11F

FY12F

11th plan10th plan9th plan8th plan

12,282MW 19,015MW 21,095MW ~50,000MW


Coal-based power generation capacity (86GW) is 53% of the total installed capacity (162GW) in the country and it contributes 66% of the generation (in kWh). We have identified 105 thermal-generation plants currently in operation throughout India, and another 59 which we expect to come into production over the next three years.

Figure 60

Demand for thermal coal in power generation


Demand 426 451 542 603 657 711

Domestic supply 374 387 432 473 489 522

Imports 52 64 110 132 168 189Source: CLSA Asia-Pacific Markets

India’s thermal-coal capacity expansions have struggled to deliver in recent years and we believe they are unlikely to accelerate in line with demand (see supply section). Consequently, the ramp up in Indian thermal-power generation will lead to a surge in import demand for thermal coal, heavily weighted towards the next two years.

Growth in power demand has lagged

behind that in GDP

Better performance in achieving targets under

11th plan than in the past

The number of thermal generation plants will rise

over 50% in three years

No production has started for coal blocks

allocated after 2004

Ramp up in thermal generation will require

more coal imports



The Ministry of Power expects coal imports for the power sector to increase from 16 million tonnes in FY09 to 68 million tonnes in FY12. We expect the imports to exceed these estimates significantly in FY12. For FY11, 35 million tonnes of imports have been targeted for blending purposes for power projects. The imports of dedicated imported coal based power projects alone would be over and above this.

Figure 61

Demand/supply balance for coal for power in FY11 and FY12¹

(mt) FY11 FY12

Demand

Coal requirement for existing capacity 426 451

Coal requirement for FY11 additions 25 91

Total demand 451 542

Supply

Coal India 335 355

SCCL 31 33

Captive mines 22 22

Total supply 388 410

Gap 63 132

Imports required to fill the gap 43 90¹ Calculations are done for 85% PLF. Source: CLSA Asia-Pacific Markets

Figure 62

Actual and expected imported coal requirements (for power sector¹)

90

43

28

16

101010

5334

0

10

20

30

40

50

60

70

80

90

100

FY02 FY03 FY04 FY05 FY06 FY07 FY08 FY09 FY10CL FY11CL FY12CL

Actual imports(mt) Requirement

¹ This is only for utilities and does not include captive power projects. Source: Ministry of Power, CLSA Asia-Pacific Markets

We believe it is too simplistic to assume that all gaps in domestic-coal production would be filled up by imports, for example; there are many project locations in the country where it would be uneconomical to transport the imported coal from the ports. Thus, the utilisation rates for the projects where imported coal is not an option would likely be cut if domestic-coal supply is not available.

India has a number of geographical advantages to becoming a significant coal importer. Given the volume of iron ore and other materials imported in China from Brazil, there is a considerable surplus of empty ships making the return journey. Thus ship owners will charge very low rates for vessels to carry a coal cargo from Australia or Indonesia into India, en-route back to the Atlantic market. Also, India is positioned significantly closer to Indonesia and South Africa than Europe and North Asia, so will see a much cheaper landed

Coal imports are likely to increase significantly over

the next three years

Official import forecasts are conservative

India is well positioned geographically to be a

coal importer

Some thermal plants find it uneconomic to

import coal

There is a significant gap between demand and domestic coal supply



cost of coal. For energy this is not so important given energy is not traded across borders, but for steel this is a significant advantage for the Indian steel industry in turning increasingly toward coking-coal imports.

Other reasons why we are positive on India’s prospects to become a major thermal-coal importer are that India’s coal is mostly located in the north and northeast, and the logistics troubles of moving coal to the coast to ship around the coast is very problematic, especially when that area is also one of the major iron ore production bases. The presence of Naxalite rebels is also a major barrier to further infrastructure investment in the area. Additionally, India has an extensive coastline, so seaborne imports make considerable sense for power plants located in the south and west of India as imported coal does not need to travel too far inland. We believe these factors contribute upside to our thermal-coal import volume forecasts. For more detail on this view see Appendix 4 on India’s prospective power demand growth

North East Asia - Limited potential For much of the last decade Japan, Korea and Taiwan have accounted for a combined 35% of thermal-coal imports. Limited growth prospects both in the energy intensive parts of their economies, combined with rising environmental pressures, mean that their contribution to thermal-coal demand is unlikely to change much in the future.

Japan is the largest single import country for thermal coal. After growing at a near 7% pa pace over 2000-05, Japan’s thermal-coal imports have been steady since 2006. Japan’s total power generation over the 2000-09 period experienced a sub 1% Cagr, but thermal generation managed a 2% Cagr as it benefitted from liberalisation of the market in 2000 and problems with nuclear generators in the following years.

Figure 63

Japanese thermal-coal demand in power generation

0

10

20

30

40

50

60

70

80

90

100

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Total power coal consumption Coal imports('000 tons)

Source: Ministry of Finance, Ministry of Trade and Industry (METI), CLSA Asia-Pacific Markets

Power-consumption growth should continue to track the subdued pace of economic growth for the next few years. In addition to anaemic total demand growth, thermal generation is also likely to lose market share as the rising environmental focus encourages a shift towards cleaner fuels. Consequently, we are expecting Japan’s thermal-coal imports to actually contract slightly over the next decade.

Domestic infrastructure constraints make imports

more attractive

Japan, Korea and Taiwan account for 35% of

coal demand

Thermal generation in Japan has outpaced total

power demand

Japanese thermal generation has been flat

since 2005

We don’t expect any growth in Japanese imports



Figure 64

Korea power generation by fuel

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

2002 2003 2004 2005 2006 2007 2008 2009

Thermal Other(Gwh)

Source: Kepco, CLSA Asia-Pacific Markets

Korea has a similar story to Japan, in that thermal-generation growth has outstripped total generation growth through the 2000’s, but will lag from now on. Between 2002-09 total power generation in Korea had a 5% Cagr, but thermal generation had a 7% Cagr. Thermal-generation capacity in Korea has risen from 16GWh to 24GWh, but there is very little expected in the way of further capacity addition. Instead, investment in power generation is being focused on nuclear and renewable, although the latter will be growing from a low base. Given the relatively strong economic GDP forecasts for Korea of 5.5% pa for the next two years, will still have thermal-coal imports rising over the next five years despite these relative trends against the industry.

Europe - Downtrend to continue As with Northeast Asia, limited growth prospects in energy-intensive sectors of the economy provide for an unexciting demand environment. In fact we expect demand for thermal coal to decline over time as more aggressive environmental policies encourage a switch to cleaner energy sources, while plentiful gas supply from the CIS will serve to keep thermal-coal consumption in electricity generation under pressure in the years ahead.

Figure 65

European energy consumption by fuel

Hydro7%

Nuclear10%

Gas34%

Oil33%

Coal16%

Source: BP, CLSA Asia-Pacific Markets

European coal demand will continue to decline amid environmental pressures

Korean coal demand will still grow on the back of

economic strength

Korean power demand growth has been rapid in

line with the economy

Coal is a relatively small share of European

energy consumption



According to the BP statistical review, European and CIS coal consumption peaked in 1979 and has been declining ever since, by a total of 40% through to 2008. Over the same time period gas consumption has increased 80%. Since 2003 coal consumption has been declining at a 2.5% annualised rate. While 2009 was depressed by economic weakness, we would expect a continuation of the trend in declining coal consumption, which will put pressure on the regions thermal-coal imports, although these may be offset to some degree as coal mines within Europe come to the end of their useful lives and rising environmental pressures limit the possibility for output expansion.

North America - Absent from the market Except for Canadian thermal imports from Columbia, North American coal markets are largely self contained. Cheap gas prices and the abundance of shale gas in the USA, combined with rising environmental pressures, could actually lead to reduced demand for coal over the years ahead despite economic growth. We therefore don’t consider the North American market to have any influence in growth on the demand side of the thermal-coal market.

Emerging markets - Plenty of potential Asean thermal-coal consumption achieved a 5% Cagr in the five years to 2009, according to the BP statistical review. We expect economic growth in this region to stay above a 5% pace for the next few years, and on this basis, we would expect an acceleration in the regions thermal-coal demand. Thermal coal has a relatively smaller share of power supply in this region however. In particular, coal only provides 7% of Malaysia’s energy and 15% of Thailand’s. For the region as a whole, coal only accounts for 23% of energy consumption, with oil taking 43% and gas 29%.

Figure 66

Asean energy consumption by fuel

Gas29%

Oil43%

Hydro5%

Coal23%

Source: BP, CLSA Asia-Pacific Markets

Excluding Indonesia and Vietnam, coal supply in the region has achieved a 4% Cagr over the period. We expect the region to increasingly be supplied with coal from Indonesia and Vietnam in the future, and thus have import demand rising by a 4.5% Cagr through 2015.

Latin America is not very significant for coal, given that the region as a whole only sources 4% of its energy consumption from coal. Hydro has a 28% share of energy for the region as a whole and a 40% share in Brazil alone. With a significant volume of oil and gas reserves in the region, we expect future energy needs to be less coal intensive. Consequently, our growth forecasts for thermal coal in the region are quite subdued.

North America has little bearing on the

seaborne market

Latin America uses little coal

European coal demand has been falling since 1979

Emerging markets will see accelerating growth

Import growth in Asean region will accelerate

Coal’s share of energy consumption lower than

oil and gas



The Middle East is another region which will be dependent on non-coal sources of energy to feed its economic growth, while African consumption (outside of South Africa), is growing from an extremely low base as to be insignificant in our forecasts.

Coking coal China - Import requirement rising strongly Steel production accounts for more than three-quarters of China’s coking-coal consumption, with other coking-coal consumers being other metallurgical industries.

Figure 67

China’s coal consumption by sector

Fertilizer(incl other coal-based

chemicals)4%

Cement(incl other construction

materials like glass)14%

Steel16%

Other¹17%

Powergeneration

49%

Total coal consumption in 2009 = 3.2bn tonnes

¹ Used by households, steam locomotives and other end-users. Source: CCTD, CRR

While steel production rose from 130 million tonnes in 2000 to more than 500 million tonnes in 2008, China remained largely self sufficient in coking coal, importing only 6.9 million tonnes in 2008. China also managed to sustain coke exports over that time, with exports peaking at 15 million tonnes in 2007, and declining to 12.1 million tonnes in 2008.

The year 2009 saw a major shift in China’s coking-coal trade position, as the world steel industry shut steelmaking capacity causing coal and coke prices to collapse. China’s coke exports dropped to only 540,000 tonnes in 2009, but have since recovered, running at a five million tonnes annualised rate in 3Q10. China’s coking-coal imports rose from 6.9 million tonnes in 2008 to 34.5 million tonnes in 2009.

Figure 68

China steel and coking-coal production growth

(20)

(15)

(10)

(5)

0

5

10

15

20

25

30

1992 1994 1996 1998 2000 2002 2004 2006 2008

China crude steel production YoY

China coking coal production YoY

(%)


Chinese coking-coal supply was sufficient to support

steel growth until 2008

Steel production drives Coking-coal consumption

Steel accounts for 16% of China’s coal consumption

China became a majorcoking-coal importer

in 2009

The Middle East is another region which doesn’t use

much coal

Coking-coal production kept pace with steel

demand until 2008



We expect China to continue the trend of moving towards larger blast furnaces, which would translate to a higher consumption growth rate for HCC over semi soft. It is also likely that we will see more steel mills in China invest to take more PCI as a substitute for HCC. Around 10% of China’s current net coal consumption is PCI, and this has been increasing over the past decade. According to one industry estimate, PCI injection rates in blast furnaces have risen from under 130kg/tonne of steel in 2000 to near 160kg/tonne currently.

As China’s domestic sources of coking coal have been suffering amid industry consolidation (see supply section from page 79 for details), and seaborne coking-coal prices collapsed in 2009, China began to turn to the global market to feed its furnaces. Initially industry participants thought China was just importing surplus global coal supplies as Western world steel producer’s suspended purchases, but these import levels have remained surprisingly resilient even as seaborne coking-coal prices have reaccelerated.

Figure 69

China coking-coal trade balance

(20,000)

(10,000)

0

10,000

20,000

30,000

40,000

2004 2005 2006 2007 2008 2009 2010Jan-Sep

Net import from coke trade

Net import from coking coal trade

(kt)


China’s coking-coal imports over the first three quarters of 2010 were 33 million tonnes, up 25% YoY. We believe domestic coking-coal output will struggle to meet demand growth from steel mills in the years ahead, and China will see rising coking-coal imports as a result. With China’s steel mill expansions being based on larger furnaces, structurally demand for hard coking coal will outpace that for semi soft. The continuing increase in technical requirements for the industry, with the industry policy now being for a minimum 300-metre furnaces, also contribute to this structural shift in demand towards higher grades. Additionally, despite steel demand gradually shifting inland, major steel expansions are still planned largely on the coast, such as the Baosteel and Wuhan projects in Guangdong, meaning imports will have favourable logistics costs versus domestic coal supply.

Import of coking coal will rise in China due to more large blast furnaces and

coastal mills

China’s PCI consumption will continue to advance

The swing in China’s trade balance is structural



Figure 70

China crude-steel production breakdown

Non-coastal32%

Costal68%


We believe China’s steel consumption still has significant growth potential for the rest of this decade, albeit at a slowing pace (see Appendix 3 on China’s long-term steel demand). China’s steel consumption only looks like growing 11% in 2010, a sharp slowdown from the 21% growth seen in 2009. We expect steel consumption growth of only 5% in 2011, as stimulus-related consumption, which has been the driver of demand in 2009 and 2010, gradually comes off.

With this solid foundation for consumption growth, we forecast China’s crude steel output to achieve a 5.8% Cagr over the next 10 years. The growth rate in coking-coal consumption will be slightly lower, but still above 5%, as scrap recovery in China will rise later this decade.

Figure 71

China crude steel production versus coking-coal imports

0

100

200

300

400

500

600

700

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Coking coal consumption

Coking coal domestic

Coking coal imports

(%)

Source: NBS, CLSA Asia-Pacific Markets

One threat to demand growth for the premium coals could be the prevalence of alternative steel-making technology, such as Finex or HIsmelt. Finex plants aim to utilise lower grade raw materials to still produce a decent grade of steel and raise environmental efficiencies. While they have achieved some success with their small plants, it is debateable whether this will be replicable for larger furnaces. Overall, we do not expect a switch to alternative steel-making technologies being of a large enough scale to change the fundamental demand picture in China for HCC imports, at least not within the next five years.

A 5.8% Cagr in Chinese steel production

through 2020

Alternative technology in steel-making is a long-

term threat

Two-thirds of Chinese steel is produced in

coastal provinces

China steel consumption still has significant

growth potential

Coking-coal imports will feed most demand growth



Post 2020, coking-coal demand in China will suffer the same fate as iron ore, that steel scrap will begin to emerge as a serious supply of iron units towards the end of this decade, at a time when China’s steel consumption has peaked, thus negating the need for virgin iron units. From then on, the coking-coal market will have to rely on new markets to maintain any consumption growth. For more on scrap, see Appendix 3.

India - Slow pace of steel expansions limiting growth We see Indian steel demand growing strongly in the years ahead as we have a bullish outlook on India’s economic growth and particularly steel-intensive infrastructure spending which we expect to step-up over the next few years. While some projects remain mired in issues relating to land acquisition and financing, the “maturing” of the huge pipeline of infrastructure investment, the policy thrust in areas like roads and the achievement of “critical mass” in term of private-sector participation are key positives. A recent mid-term appraisal of the 11th Five-Year Plan (FY08-12) highlighted that infrastructure spend in the first three years was broadly in line with target and that the private sector had, in fact, executed above target. Over next five years, we estimate infrastructure spending in India at a huge US$680bn.

Momentum is clearly building in the economy and in steel consumption. India was the only market outside of China which saw steel consumption grow in 2009, and is now the world’s fifth-largest steel market. Unfortunately for India the pace of expansion in the domestic steel industry looks likely to lag demand.

Land-access issues continue to hamper most producers’ plans for building new steel mills in India. Arcelor Mittal and Posco are two of the highest-profile steel producers who’ve had difficulty progressing with their Indian investment plans, but there are many others besides. Despite these difficulties, we still expect Indian steel production to rise over time, from 60 million tonnes in 2010 to 88 million tonnes in 2015.

Our demand forecast sees Indian steel consumption rising from 56 million tonnes in 2010 to 98 million tonnes in 2020, meaning India will become a net importer of steel in the next few years. Eventually, we expect the Indian government to take the view that steel imports are wasteful given the country has abundant iron-ore reserves, and thus make it easier for investment in the sector, but we wouldn’t get our hopes up on this happening until after 2015.

Figure 72

Indian steel demand versus domestic steel supply

30

40

50

60

70

80

90

100

04 05 06 07 08 09 10 11CL 12CL 13CL 14CL 15CL

Finished steel demand

Finished steel production

(mt, y/e March)

Source: CLSA

Indian steel demand to be boosted by

infrastructure spending

Indian steel production will lag demand

India will become a net steel importer

Steel demand will outpace supply

Scrap is another threat to coking-coal consumption,

but not until 2020



Most incremental Indian steel capacity will be from large blast furnaces, which will require HCC. There will also be improved demand growth for HCC from existing steel capacity as it is upgraded. Indian steel mills have among the highest coke rates of any steel industry in the world, averaging over 550kg per tonne of steel. This is because many steel plants such as those at SAIL (which accounts for 20% of India’s production) were set up decades ago and are very inefficient. However, many of these are now being upgraded or will be replaced with larger furnaces. While this will improve the coking-coal efficiency rates, the demand will be increasingly biased towards higher-quality coals.

Figure 73

Indian hard coking-coal demand

30

35

40

45

50

55

60

65

70

75

80

07 08 09 10 11CL 12CL 13CL 14CL 15CL

(mt, y/e March)


Given that India is lacking in quality coking-coal reserves, most of this demand growth will be fed by imports. While we have HCC demand rising 70% over the next five years, we expect domestic output will struggle to grow 25%. We therefore expect HCC imports to nearly double over the next five years.

Figure 74

Indian HCC imports

(mt) 08 09 10CL 11CL 12CL 13CL 14CL 15CLHCC consumption 37 40 46 52 57 66 75 78HCC domestic output 15 16 15 17 17 18 18 19HCC imports 22 24 31 34 40 48 57 59Source: CLSA Asia-Pacific Markets

North East Asia - Moderate growth to continue For much of the last decade Japan, Korea and Taiwan have accounted for a combined 40% of seaborne coking-coal imports.

For coking coal, there are a few steel mill expansions planned for the near term. In Korea, Hyundai Steel opened its first four million tonne blast furnace in April 2010 and will open the second four million tonne furnace in December. Posco is also expanding, although mostly through the traditional blast furnace route than by using its own Finex technology. In total, we expect Korean coking-coal imports to rise to 28.6 million tonnes by 2015 from 19.3 million tonnes in 2009.

Japan, Korea and Taiwan growth prospects

are limited

Upgrading of blast furnaces will require more

hard coking coal

HCC demand in India will almost double in five years

This HCC will mostly be supplied by imports

Imports will supply most of India’s HCC requirements

Steel output expansion will be limited to Korea



Outside of Korea, Dragonsteel is expanding in Taiwan, while in Japan there are no capacity additions planned. Debottlenecking and blast furnace relines may lead to some capacity creep, but on the whole steel production will be steady over time, in line with lacklustre economic growth.

In total, we expect demand for 98 million tonnes of coking coal in North Asia in 2015, of which 57 million tonnes will be HCC. This compares to demand of 77.1 million tonnes and 45.9 million tonnes in 2009, against the peak of 94 million tonnes coking coal and 53.5 million tonnes HCC imports in 2008.

Europe - Holding steady For coking coal, Europe remains the leader in PCI consumption from a technical perspective. The most technologically advanced PCI consumer is the Corus plant at Ijmuden, which manages to use over 220kg of PCI per tonne of steel production, thus reducing their HCC requirement to only around 250kg per tonne of steel. This is viewed by many as being the structural limit for PCI consumption, but could be used as a model for the rest of the world to follow as HCC premiums widen.

Growth in European steel consumption will mainly come from East European countries which will still see a decent pace of economic growth. Demand in Western Europe will likely be flat for the next five years.

If environmental pressures and associated costs grow in Europe at a faster pace than elsewhere, European steel furnaces may be closed and production moved to places with good raw materials access such as Brazil. Thus absolute coking-coal consumption in Europe could decline over time, although we expect this risk to only arise post 2015.

North America - Absent from the seaborne market North American coal markets are largely self contained. For metallurgical coal, there is not much in the way of demand growth given our expectation for steel demand to remain largely depressed in the years ahead. We therefore don’t consider the North American market to have any influence in growth on the demand side of the coking-coal markets.

Emerging markets - Nothing outside of Brazil Our expectations for steel demand in emerging markets are quite positive, with an 8% Cagr during 2010-13, but the feed through effect to coking-coal seaborne trade is quite limited. Outside of Brazil there are no other emerging markets which import much more than a million tonnes of coking coal, excluding the CIS countries which basically trade between themselves.

We expect steel production in Latin America to have a 9% Cagr through 2013, and most of these expansions will be blast furnace based, especially in Brazil. Brazil already imports almost all its 18 million tonnes coking-coal requirement as the country has little domestic supply, so almost all the growth in steelmaking demand will be fed by coking-coal imports. While North America would be the main logical supply source for coking coal to Brazil, the country will actually benefit from cheap logistics from Australia and Africa. As iron-ore vessels carry cargoes into Asia and return empty, they will charge only a small fee to carry a return cargo of coal into Brazil. This is something Vale has highlighted for their Mozambique project.

North America is largely self contained for

coking coal

Brazil is the only significant importer of

coking coal

No expansions planned in Japan

Japan, Korea and Taiwan coking-coal imports

overall will be flat

European mills are technically advanced, having high PCI rates

Eastern Europe will provide the only steel

demand growth

Coking-coal consumption in EU may fall after 2015

Steel demand outlook for emerging markets

is positive

Section 4: Swing supply factors Coal outlook


Swing supply factors Coal is the most widely available and well distributed fossil fuel in the world. The USA has the largest proven coal reserves, followed by Russia, China, Australia and India.

Figure 74

Global coal reserves

(Bn tonnes) Coal reservesUS 238,308Russian Federation 157,010China 114,500Australia 76,200India 58,600Ukraine 33,873Kazakhstan 31,300South Africa 30,408Others 85,802Total world 826,001Source: BP, CLSA Asia-Pacific Markets

Given that most countries are at least partly self sufficient in coal supply, the traded seaborne coal market only accounts for about 11% of total coal consumption. This ratio is very small in comparison to other commodities. For iron ore, over half of the material is consumed in a different country to where it is mined, while for copper, lead and zinc over three-quarters of consumed material is acquired from overseas.

Figure 75

Percentage of traded market in total consumption by material type

0

10

20

30

40

50

60

70

80

90

100

Iron ore Copper ore Coal Lead ore Zinc ore

(%)

Source: UN, CLSA Asia-Pacific Markets

World coal production will exceed seven billion tonnes for the first time this year, but total exports of coal will be under one billion tonnes. Of this export volume, a considerable proportion is exported overland by railcar, such as between the CIS and Europe. For the purposes of this report, we are only interested in the seaborne coal trade, which is around 800mtpa for thermal coal, and under 250mtpa for coking coal. We are also interested in the overland trade between Mongolia and China, as the viability of this coal trade will be extremely dependent on seaborne coal market prices.

Seaborne traded coal market is relatively small

World coal production will exceed seven billion

tonnes in 2010

Coal is the most widely available fossil fuel

Coal reserves are very dispersed

Coal is one of the least traded commodities



Australia and North America will remain the key countries of supply for coking coal, with Mongolia, Mozambique and the CIS countries providing new tonnes to the market. For thermal coal, Indonesia is already the largest supplier to the seaborne market and will see considerable growth even from these levels in the two years before Australia sees a significant increase in infrastructure capacity. In the long run, Mongolia could become a serious supplier to China.

While we expect China to be a highly price sensitive swing buyer in the seaborne market, we view China as no longer significant as a supplier into the seaborne coal market. It is quite clear that China’s rising focus on health, safety and the environment means that it is no longer willing to export cheap, low value products such as coal when it needs so much of the stuff for itself. Government policy reflects this view quite clearly, with the government having cut export quotas for thermal coal and coke and significantly increased export taxes in recent years.

The view that China will not be a major supplier of coal is also reflected in trade policy in other sectors. As China becomes richer, it has less need to rely on low value exports, particularly of materials which provide pollution or safety risks to the domestic market, and for which China will require to consume itself in the longer term.

Thermal coal Indonesia is the largest supplier to the seaborne thermal-coal market, but will see its share of supply shrink over the next five years as tougher geology and logistics for mine expansions mean it is increasingly difficult to expand production at the same pace seen in recent years, while rising domestic demand limits export volumes. Australia will gain the most market share as infrastructure expansions in New South Wales see an aggressive increase in exports from 2012. Elsewhere, expansions in South Africa and Colombia will be enough for them to maintain current market shares, but other countries will become increasingly less important to the seaborne market over time.

Figure 76

Figure 77

Thermal-coal export share, 2010

Thermal-coal export share, 2015

China2%

Other Asia3%

South Africa8%

Russia12%

USA3%

Colombia9%

Others12%

Australia18%

Indonesia33%

USA1.9%

Colombia7.8%

Others6.5%

Russia8.2%

South Africa6.7%

China0.4%

Other Asia3.1%

Australia35.3%

Indonesia30.1%


Indonesia - Strong growth to continue Indonesian coal exports have surprised on the upside for the past few years, with a seemingly endless growth in supply. Indonesia is largely absent from the coking-coal market. Only a handful of mines produce coking coal, and they lack the reserves to expand production. Consequently, we do not separate out Indonesia in our coking-coal supply model.

Australia and North America important for coking coal, Indonesia

for thermal

China will no longer be a coal exporter

China is pulling out of many low value export sectors,

coal is part of this trend

Australia to gain market share, Indonesia to lose



Indonesian production has had a 12% Cagr over the past five years. This is arguably the fastest in the world, faster than China’s 9%, Australia’s 3%, India’s 6% and the world’s 5%. This has underpinned Indonesia’s rise to become the world’s largest thermal-coal exporter, overtaking Australia.

Figure 78

The coal industry’s rate of production growth 2005-10

3

5

6

8

9

12

0

2

4

6

8

10

12

14

Indonesia China Asia Pacific India World Australia

(2005-10 Cagr, %)

Source: CLSA Asia-Pacific Markets, BP

Figure 79

Indonesia’s production growth trajectory

231

249 249

290

320

170160

180

200

220

240

260

280

300

320

340

2005 2006 2007 2008 2009 2010F

(mt)

Source: CLSA Asia-Pacific Markets, BPS, Ministry of ESDM

Going forward, we believe the rate of production will slow from a 12% Cagr in 2005-10 to an 8% Cagr over 2010-15. A higher base is one of the reasons, as it is now more difficult for coal producers to increase production versus five years ago, plus more heavy equipment is needed. A 1% of production growth now implies nearly double the tonnage from five years ago, not to mention the higher strip ratio compared to five years ago which means greater overburden needs to be removed. This brings us to the second reason, that lead-times for heavy equipment delivery are increasing. This has typically been around six to eight months during good times, but in the high demand period like today it could be as long as 12-18 months. During such high demand period too, the typical equipment shortages such as tyre shortages could re-emerge again, further limiting the upside in production.

Indonesia thermal-coal production has grown the

fastest for five years

Production growth likely to weaken in 2010-15

Indonesia has seen the fastest pace of coal production growth

Production growth in 2010 held back by heavy

rains in 2H



Figure 80

Indonesia's production profile 2005-15

Cagr (%) (mt) 2005 2006 2007 2008 2009 2010F 2011F 2012F 2013F 2014F 2015F

2005-10 2010-15 2005-15

Bumi Resources 45 52 54 53 63 66 73 85 96 109 113 8 12 20

Adaro 27 34 36 38 41 42 47 52 57 63 69 9 11 21

Kideco 18 19 19 22 25 28 31 34 37 40 40 9 7 17

ITM 14 21 20 20 21 23 26 27 26 25 25 10 2 13

Berau 9 11 12 13 14 17 20 24 28 30 30 13 12 27

Bukit Asam 9 9 9 10 11 14 17 19 22 27 32 10 18 30

Others 48 86 100 93 111 131 148 156 154 157 159 17 3 21

Total Indonesia 170 231 249 249 286 320 361 396 422 450 468 12 8 21

Source: CLSA Asia-Pacific Markets, Ministry of ESDM

Figure 81

Contract-miners’ strip ratio increases

5.0

5.5

6.0

6.5

7.0

7.5

8.0

8.5

9.0

2005 2006 2007 2008 2009

(x) Pama Buma

Figure 82

Production growth of 1% suggests a lot of additional coal and overburden now

2005 2010 % growth

Production (mt) 170 320 88

Estimated industry strip ratio (x) 7.0 8.1

1% growth implies:

Coal production (mt) 2 3 88

Overburden removal (m bcm) 11 21 98


Worth highlighting too is the fact that a lot of small mines opened up in 2007, which drove a large portion of the total production growth over the past five years. This smaller mines have grown in importance from less than 20% of Indonesia’s production pre-2005, to now some 30%, but we expect this to revert back to 25% over the next five years. We see stagnant production from the small mines for the next five years. Not only is the industry (East and South Kalimantan to be exact) more saturated now compared to five years ago, a lot of new small mines opening going forward would likely replace those small mine reserves which are now depleting. Investment cost

Small mines production ramp-up is now limited by

their depleting reserves

Both investment and production cash cost for

new small mine is going up

Strip ratios are rising, leading to higher costs



for new mine opening as well as the production cash cost going forward are also arguably higher than five years ago. This is largely due to longer hauling distances and costlier infrastructure, as strategically-located assets (close to the port and infrastructure) have become scarcer. Hence, new mine openings, particularly those smaller mines, would be more remotely located and thus would have costlier transhipment costs.

Arguably, the investment cost of new mine opening for the larger firms will be more benign as typically their source of growth will be brownfield expansion, although higher production cash cost is inevitable due to higher strip ratio and longer in-pit hauling distances. We thus expect these larger mines, which now form some 75% of Indonesia’s total production, will lead the growth going forward. We do not foresee port capacity in East and South Kalimantan as production growth bottlenecks.

Figure 83

Small versus large mines as % of production

20

30

40

50

60

70

80

2005 2006 2007 2008 2009 2010F 2011F 2012F 2013F 2014F 2015F

Large mines

Small mines

(%)

Source: CLSA Asia-Pacific Markets, Ministry of ESDM

We highlight that future upside will be coming from the underdeveloped Sumatra production. However, this entails a lot of railway and infrastructure investment which takes a lot of amount of time and money. Once this railway infrastructure has been developed, we will see a substantially more coal output from Indonesia. South Sumatra still has the biggest coal reserve in Indonesia after all. We currently only expect Kereta Api Indonesia’s (KAI) debottlenecking on existing railway and PTBA-Transpacific’s railway project to go ahead and start commercial operation by 2015. Central Kalimantan could also offer upside to Indonesia’s coal production, but more on coking-coal output, to a lesser extent to the thermal-coal output. That said, similar to South Sumatra, major development in this region would also entail a huge amount of railway and infrastructure investment.

Figure 84

Prospective coal railway projects in 2010-15

Project's owner Project type Capacity KAI (Kereta Api Indonesia) de-bottlenecking from 11.6mtpa in 2010 to 22.7mtpa in 2014 PTBA-Transpacific greenfields 25mtpa by 2014-15 Adani greenfields 35mtpa by 2014-15 Reliance greenfields 50mtpa by 2015


Investment cost for new mine opening for the larger

boys will be more benign

Future production upside to come from Sumatra, as

Kalimantan is saturated

Large mines will take share from small mines



Figure 85

Sumatra still has the biggest untapped coal reserves in Indonesia after all; the future of Indonesian coal?

Source: Ministry of ESDM

Indonesian exports Indonesia will continue to be a key net exporter in the global seaborne thermal-coal market. However, Indonesian exports are likely to grow at even a much slower pace than production, at only a 6% Cagr in 2010-15, which is a significant reduction from a 15% Cagr registered in 2005-10. Domestic demand will be growing at an increasingly rapid pace, a 14.5% Cagr in 2010-15 versus a 7.8% Cagr in 2005-10. Thanks to Perusahaan Listrik Negara’s recent efforts to bolster the nation’s electricity capacity which are finally coming to fruition over the next five years. We have seen more evidence that the additional capacity is starting to come into the market. Against a softening production growth going forward and soaring domestic demand, a slowing export volume growth seems inevitable over the next five years.

Figure 86

Indonesia’s production versus domestic demand and exports

0

50

100

150

200

250

300

350

400

450

500

2005 2006 2007 2008 2009 2010F 2011F 2012F 2013F 2014F 2015F

Total production

Export

Domestic consumption

(mt)

Source: CLSA Asia-Pacific Markets, Ministry of ESDM, BPS

Indonesia to remain a key exporter, but export growth

will slow in 2010-15

Domestic consumption will take an increasing

share of coal production



Figure 87

Export as a % of Indonesia thermal-coal production

72

73

74

75

76

77

78

79

80

81

82

2005 2006 2007 2008 2009 2010F 2011F 2012F 2013F 2014F 2015F

(%)

Source: CLSA Asia-Pacific Markets, Ministry of ESDM, BPS

Figure 88

Additional power capacity (including existing IPP projects) and resulting coal demand

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2010F 2011F 2012F 2013F 2014F 2015F

(mt)(MW)

0

4

8

12

16

20

24Additional power capacity (LHS)

Additional coal demand for power, incl existing IPP projects

Source: CLSA Asia-Pacific Markets, PLN

Figure 89

Indonesian export growth forecasts

129

183195 200

231

260

286304

318334

350

0

50

100

150

200

250

300

350

400

2005 2006 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

(mt)(mt)

0

10

20

30

40

50

60Export (LHS) Change YoY


Exports to decline as percentage of production

Significant additional power capacity planned

Pace of export growth to slow



As the domestic market needs to be prioritised due to Domestic Market Obligation (DMO), we view there is more downside rather than upside to Indonesia’s expected export volumes going forward. Although delays in the power plant projects could still happen, the ultimate amount of additional power capacity and the resulting coal volumes over the next five year period is unlikely to vary much from our current expectation. In fact, this has not factored in upside for the second phase of 10GW project, which would be 30-40% coal-fired as well as any upcoming IPP projects. That said, we believe it will be down to the production volumes. In other words, production upside and downside would bring upside and downside to Indonesian export volumes, respectively.

Weather also brings downside risks to the forecasts, as seen this year. East and South Kalimantan in particular are prone to suffer in the wet season, though our forecasts always account for some seasonality, the outcome will be variable year by year.

Meanwhile, export tax will not be a threat for Indonesia, in our view. Even if it is passed, it will not be effective because 75% of Indonesia’s production is coming from the first generation of CCoW holders which are legally not affected by any new regulations or taxes or duties, unless stated in their CCoWs. Therefore, we see little incentive for the Indonesian government to pass such a tax going forward.

Any means to secure domestic demand has been articulated via DMO regulation. If the company breaches this, it will face an export and production quota the following year. Although not yet enforced, it is likely that those with higher rank coal production could trade with the lower rank peers to meet their DMO volume obligations

Australia - All about infrastructure Australia supplies about 20% of the seaborne thermal-coal market, but is set to aggressively expand its share as infrastructure becomes available. Australia’s thermal-coal exports mainly come from New South Wales. Rail Infrastructure Corporation (RIC) owns NSW’s rail infrastructure and leases the non-metropolitan rail network to Australian Rail Track Corporation (ARTC) under a 99-year lease. RailCorp runs the metropolitan lines, including that from Wollongong to Newcastle.

Coal haulage in NSW occurs on the Hunter Valley Rail Network, which is an interconnected system between the coal mines in Hunter Valley, Gunnedah and Western Basins and the ports in Newcastle and Port Kembla. Tonnage is dominated by Asciano-owned Pacific National, which transports an estimated 80% of NSW’s export coal. The other major player is QR, which handles the remaining 20% of tonnage in the ARTC system.

Ports NSW has three operating coal ports in Newcastle, Port Waratah Coal Services’ (PWCS) Kooragang and Carrington terminals and Newcastle Coal Infrastructure Group’s (NCIG) terminal, and one terminal in Port Kembla, Port Kembla Coal Terminal. Newcastle is currently the dominant port, transporting 90.5 million tonnes of the 103.7 million tonnes exported from NSW in 2009.

The NCIG coal terminal will eventually be expanded to 66mtpa. The 30mtpa first-stage expansion was completed in February 2010. Stage 2 will see production capacity increase by 36mtpa to 66mtpa. A 20mtpa expansion of

There is more downside to export than upside

going forward

Export tax is not a concern for Indonesia

Domestic market security is via DMO regulation

Australia supplies 20% of the thermal-coal market

Newcastle’s three ports dominate export volumes

Hunter Valley Rail is the backbone of NSW

coal exports

Port expansions are underway



PWCS’ Kooragang is likely to be completed in mid-2012 at a cost of A$570m. The addition of a fourth shiploader at PWCS’ Kooragang terminal could lift port capacity by a further 12mtpa by 2013.

Capacity forecasts Port capacity will continue to constrain NSW’s coal exports in the medium term. The Hunter Valley rail network has a theoretical capacity of 162mtpa and the inclusion of additional rail loops could lift this beyond 200mtpa. The 66mtpa NCIG and a further 15mtpa third-stage expansion plus stage 4 will need to be completed before current rail capacity is reached. Given the time required to achieve this, we believe ARTC will be able to plan further expansions to ensure rail capacity continues to exceed port capacity in NSW.

Figure 90

NSW’s coal rail and port capacity

0

50

100

150

200

250

300

350

400

450

500

08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16

(mtpa) Port Capacity Rail Capacity

Source: ARTC, PWCS, NCIG, Port Kembla Coal Services, CLSA Asia-Pacific Markets

In total Australia’s thermal-coal exports will triple over the next five years as infrastructure becomes available. Thermal coal will also be seen in increasing quantities from Queensland ports as coking-coal capacity grows at a slower pace than infrastructure there. Thermal coal will see its share of Australian coal exports grow from under 50% now to near 70% by 2015.

Figure 91

Australian coal exports

(mt) 2009 10CL 11CL 12CL 13CL 14CL 15CL

Total port/rail capacity 280 300 320 400 450 550 630

Coking-coal exports 139 154 171 179 181 185 187

Thermal-coal exports 134 137 140 180 240 330 410

Thermal share (%) 49 47 45 50 57 64 69


CIS - Struggling to grow Russia produces more than 300mtpa of coal, and has 20% of global coal reserves, or 157 billion tonnes, according to the BP statistical review. Russia accounts for more than 10% of supply into the internationally traded thermal-coal market. While CIS countries are significant producers of coal, for the purpose of this report we are only interested in coal shipments into the globally traded market.

Port capacity is the limiting factor in

the short and long term

Further expansions likely

Russia accounts for 10% of seaborne thermal supply

As infrastructure becomes available, coal exports

could treble

Australian share of thermal coal exports to

grow strongly



Russian exports have been growing at no more than 3% pa in recent years, and last year totalled 90 million tonnes for thermal coal. Most of Russia’s exports go to Ukraine, Turkey and Europe, with 15-20 million tonnes going by rail, and the remainder by sea. Given that most demand growth for coal is in Asia, the Russian east coast ports are the main growth focus these days. Exports are likely to reach 30 million tonnes from its east coast ports this year, with about 80% being thermal coal.

Figure 92

Russian coal exports by port

(mt) 2008 2009 10CL

Far East 20 26 30

Baltic & Northern 43 48 32

Black Sea 24 20 22

Total 87 95 83

Sources: Metaldata, CLSA Asia-Pacific Markets

Mining costs in Russia are quite high given that three quarters of mines are underground, while the extremely long distances on the trans-Siberian rail, given most of the mines are in the centre of the country, makes their total FOB cost relatively high. At the beginning of 2010, the government raised rail tariffs for coal by 9.4%.

Even if miners can afford the high rail tariffs, the rail network is the main bottleneck for exports according to miners. Railing from mines in the western areas to export to Europe via rail or ports has reasonable capacity, but trying to rail coal to the east coast ports is very capacity constrained. Additionally there is little investment planned by the government in expanding the trans-Siberian, so the situation is unlikely to improve soon.

Another cost disadvantage for the Russian coal exporters is that their ports are generally shallow draft, meaning they can only use small vessels. This makes it prohibitively expensive to export coal from west coast ports to Asia, though given the geographical proximity of east coast ports to North Asian markets, it’s not a significant disadvantage for east coast exports.

The high production and logistics costs, combined with the growth markets for thermal coal being in South China and South Asia, mean coking coal is the only product worth expanding for export from Russia, so we don’t foresee thermal-coal exports rising much over the next five years.

South Africa - Waiting for infrastructure South Africa mostly exports thermal coal, having more than 30 billion tonnes of reserves, and currently producing 250mtpa. However, despite the abundance of coal, export volumes have seen no growth at all over the past five years due to a lack of infrastructure expansions. The Richards Bay coal terminal has export capacity of 91 million tonnes, but due to a lack of rail capacity, exports have been stuck at 61-62 million tonnes in recent years.

The rail network in South Africa is owned and operated by Transnet. As a state owned company, Transnet has strict requirements to maintain debt at low levels in order to retain its credit rating, and this has prevented it raising finance for expansions in recent years.

However, investment is finally underway to expand Transnets’ network capacity to 81 million tonnes by 2014, although there are proposals to take it all the way up to RBCT’s capacity of 91 million tonnes under review. Given

South African exports have struggled to grow

Russian exports have grown very slowly

Growth has been focused on the Far East ports to

feed Asian markets

Thermal coal exports won’t see much growth

Transnet has been slow to invest

Expansions are finally happening, but are

relatively small scale



that Transnet has struggled to move as much coal as its stated 71 million tonnes capacity in recent years, we believe it will struggle to reach the full 81 million tonnes of exports from the expansion unless there are significant improvements in operations management.

Colombia - Strong growth to continue Colombian coal exports, which include very little coking coal, have nearly doubled since 2002. Significant investment is underway in the country to further expand production, and this should feed through to a further 25% rise in export volumes through 2015.

Figure 93

Colombian exports to rise

Source: MPX Colombia

North America - Highest cost seaborne supplier The US coal industry has had some rocky times over the last several years as oversupply in the steam market has put a damper on prices only being offset on the positive side by higher coking-coal prices. Over the past several years coal producers have become more disciplined when it comes to supply demand compared to their predecessors. Historically, coal producers have not had the wherewithal to keep production off line as their balance sheets would not allow them to keep their assets in the ground. However, the recent commodity boom has allowed the major players the flexibility, as their financial situation has improved, to keep coal out of the market. The key in the short and long term is on the demand side, coming from the competition of natural-gas prices. With gas prices being as low as they are, and the environmental impacts not only on production, but on consumption, we believe the historical growth rate of coal consumption will be closer to 1% compared to the historical Cagr of nearly 2%. However, we still see a tighter steam coal market heading into the second half of 2011 as inventories will have been cut sufficiently to keep the market in balance.

Coal production, exports Total coal production in the US for 2010 is expected to be about one billion tonnes down almost 10% from 2008 levels. We are looking for steam coal production to increase in the Powder River Basin and in the Illinois Basin to offset some of the loss seen in Central Appalachia due to environmental and grade concerns and as a result do not see significant production growth in the US over the next five years.

Colombian exports will see some growth

US coal markets have been depressed by

gas prices

We don’t expect much growth in US coal

production



Figure 94

Supply and demand

(mt) Production Consumption Net exports

East West Total Utility Coking Other Total Imports Exports

Net exports

Coking coal (included in

exports)1980 573 251 824 569 67 67 703 1 92 911985 559 325 884 694 41 83 820 2 93 911990 630 399 1,029 781 39 83 903 3 106 1031995 542 491 1,033 850 33 79 969 7 89 812000 510 565 1,076 995 29 70 1,094 13 58 46 332001 526 596 1,121 973 26 67 1,066 20 49 29 252002 489 601 1,090 978 24 65 1,066 17 40 23 212003 468 601 1,069 1,005 24 66 1,095 25 43 18 222004 485 627 1,112 1,015 24 66 1,105 27 48 21 272005 493 640 1,133 1,039 23 66 1,129 30 50 19 292006 491 668 1,159 1,026 24 66 1,116 37 49 12 282007 482 664 1,147 1,045 22 61 1,128 37 59 22 322008 492 678 1,170 1,042 22 58 1,122 34 83 49 432009 458 627 1,086 943 14 51 1,008 23 59 36 3710CL 444 632 1,076 997 20 53 1,070 19 80 61 5811CL 455 660 1,115 1,007 20 53 1,080 22 82 60 6012CL 460 670 1,130 1,017 20 53 1,090 23 85 62 60Source: EIA, Credit Agricole (USA)

We do not expect the US to increase thermal-coal export volumes, as high logistics costs will be insufficient to make exports to growth markets in Asia viable despite our high price forecasts.

China - Domestic supply growth to slow China is by far the world’s largest coal producer, and has reserves of more than 1.1 trillion tonnes, 80% of which is thermal coal. Wood Mackenzie estimates total economic coal resources in China to be 221 billion tonnes.

Figure 95

China coal reserve by province

Basic coal reserve (bn tonnes)National total 326.1Shanxi 106.2Inner Mongolia 78.9Shaanxi 27.8Xinjiang 14.7Henan 11.6Anhui 8.6Yunan 7.9Hebei 6.1Gansu 6.0Ningxia 5.8Sichuan 5.0Qinghai 2.0Hunan 2.0Jiangsu 1.5Guangxi 0.8Jiangxi 0.8Beijing 0.7Hubei 0.3others 39.5Source: CEIC, CLSA Asia-Pacific Markets

Over 80% of China’s coal reserves are thermal



Coal sector reforms created incentives to produce more coal China’s coal-sector administration has been undergoing reforms since the 1990s. These took an important step in 1999, when the ownership and operation of the central government-owned mines was transferred to the provinces. This change in the ownership structure also coincided with reforms in the country’s coal-pricing structure.

Figure 96

China’s coal prices

200

300

400

500

600

700

800

900

1,000

1,100

Jan 04 Feb 05 Apr 06 Jun 07 Aug 08 Sep 09 Nov 10

(Rmb/tonne) Datong blend

Shanxi blend


According to a Stanford University paper Evolution of China’s coal institutions, by 2002 all the prices, even for power generation were relaxed and since then central government has no longer directly controlled any coal price. In 2002, about half of China’s power coal was sold by term contracts through the annual National Coal Ordering Conference and half was sold in spot markets with the Qinhuangdao port increasingly acting as the leading benchmark.

The coal-price reform created the incentive for provincial governments to produce more coal. It was also a way for provincial governments to boost tax revenue. Another factor spurring coal production was fast-rising coal demand from the power-generation sector, which was witnessing an unprecedented growth due to recent reforms.

Figure 97

China’s coal production trend

(m tonnes)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

1980 1984 1988 1992 1996 2000 2004 2008

Cagr over 1980-2002 = 3.9%

Cagr over 2002-2008 = 11.4%


Coalmine ownership transfer to provinces

spurred production growth

All coal prices, even for power generation, were

relaxed by 2002

In 2002 half of coal was sold by term contract and half sold in spot markets

Coal-price reform created incentive for provinces to

produce more coal

Coal production Cagr increased

drastically after 2002



China’s total unwashed coal output has grown from 1.25 billion tonnes in 2000 to three billion tonnes in 2009. SOEs have provided the bulk of the growth, with their output rising from 730 million tonnes in 2000 to 2.15 billion tonnes in 2009. Private output (town and village enterprises, or TVEs) has grown from 520 million tonnes in 2000 to a peak of 925 million tonnes in 2008. In 2009 their output fell to 833 million tonnes, and will this year likely be about 800 million tonnes, given the ongoing consolidation trend in the industry.

The 11th Five-Year Plan was the trigger point for the consolidation of China’s domestic coal industry. This outlined a plan to create several large-scale (100mtpa) SOE producers, while reducing the proportion of coal from small private mines. This is essentially a reversal of the policy which prevailed from 1999 and encouraged private coal production. This trend has been replicated across industries, as China looks to improve safety and environmental focus.

The move to concentrate ownership of coal assets has not slowed overall coal production growth however. Over the past two years, the major growth provinces for output have been Inner Mongolia, which has raised output by 70% from 360 million tonnes in 2007 to 617 million tonnes, or 20% of China’s total coal output in 2009. Shaanxi has seen its share of China’s coal production rise from 2% to 10%, with output raised by 58% from 181 million tonnes in 2007 to 286 million tonnes in 2009, while Xinjiang has almost doubled output from 40 million tonnes to 78 million tonnes. Seven of the top 10 fastest-growing provinces for coal output are in west China, and this trend is likely to continue.

Figure 98

China raw-coal production by province

Henan8%

Shandong5%

Guizhou5%

Anhui4%

Sichuan4%

Others24%

Shaanxi10%

Shanxi20%

Inner Mongolia20%


With greater population density in the central and eastern provinces, any additional growth in coal output will be focused on the western provinces. The western provinces have combined reserves of 140 billion tonnes, out of China’s total 326 billion tonnes according to NBS data. Shanxi has 106 billion tonnes followed by Inner Mongolia with 79 billion tonnes. With their large unexplored land area, the western provinces are also most likely to yield increased reserves.

In 2009 Inner Mongolia surpassed Shanxi as China’s largest thermal-coal-producing province. Nearly all of Inner Mongolia’s coal production is thermal coal, but the quality is not as good as from Shanxi. Much of Inner Mongolia’s coal output is lignite, with a calorific value of only about 4,000kcal. In addition to its

Inner Mongolian coal is much lower quality

Western provinces have a lot of potential

Private mine output has been falling since 2008

Consolidation efforts have not stopped supply from

new areas

The 11th Five-Year Plan triggered consolidation

Coal supply concentrated in the north



poor energy content, lignite is also harder to transport as it is structurally weaker. VIU (value-in-use) adjustments to reflect these issues are the drivers for its higher equivalent production costs of Rmb275/tonne for Inner Mongolian coal.

Mining costs for thermal coal in China are quite high in relation to the rest of the world. More than 80% of China’s thermal-coal mines are underground, and on average the costs of underground mines are at least twice that for open-pit mines. The most efficient thermal mines in China have a cash mining cost as low as Rmb150/tonne, while the least efficient can be as much as Rmb200-230/tonne. Adding in washing costs, non-mining operating costs and rail loading fees, and the average mining cost comes in about Rmb230-240/tonne, with the highest-cost mines being at Rmb280-320/tonne free on rail/truck.

Figure 99

Figure 100

Cost breakdown of middle-cost mine

Cost breakdown of high-cost mine

0

100

200

300

400

500

Mining,washing and

loading


Taxes Logistics

(Rmb/t)

0100200300400500600700

Mining,washing and

loading


Taxes Logistics

(Rmb/t)

Source: Industry source, CLSA Asia-Pacific Markets

Taxes are a more significant cost for thermal-coal mines than coking-coal mines, given they have substantially lower sales prices but most costs are levied on a per-tonne basis, albeit slightly lower for thermal than coking coal. Taxes are explained in more detail in the next section, but in summary the total tax and related cost for thermal mines is Rmb25-35/tonne depending on location. Private mines in particular have to pay significant revenue to local authorities to allow them to operate amid increasingly strict environmental and safety regulations.

The final cost segment is logistics. In many cases the total cost to truck/rail/ship coal from a mine in Inner Mongolia or Shanxi down to a southern power plant exceeds Rmb300/tonne. In total, the highest-cost mines have a delivered cost to a southern power plant in excess of Rmb600/tonne or US$90/tonne, hence the growing attraction of thermal-coal imports.

China’s reserves of thermal coal are very extensive, but the focus of investment is clearly moving to the west. We do not expect Inner Mongolia to raise output much further as logistics are very constrained, quality is poor, the province lacks water resources for coal washing, and the provincial government has introduced a rule requiring 50% of coal production to be consumed within the province. Until the power grid is improved, it is not very feasible to generate power for export, and industry capacity restrictions in industries such as steel and aluminium make heavy industry less likely to succeed in expanding. There are many proposals for coal to liquids plants in the region, but so far China only has three plants and given their dirty environmental record, the central authorities appear reluctant to allow much expansion.

Chinese mining costs are high compared to the

world average

Taxes have been rising

Logistics costs are high

Potential for further mine expansions are limited



Given the troubles for private mine owners in Shanxi, many investors in the coal sector are actively looking at assets in Xinjiang and western China for future investment, as these are areas where coal mining is likely to receive a warmer welcome. After 2015, we would expect almost all growth in coal production to be coming from the western provinces as logistics improvements come through.

Infrastructure - Barrier to growth In many cases for southern power plants one of the largest cost contributors in coal purchases can be logistics. China’s rail network currently has capacity to carry less than half the countries coal.

Figure 101

Railway transportation of coal in China

(mt) 2003 2004 2005 2006 2007 2008 2009 1H10

Coal transported by railway 886 992 1,071 1,120 1,121 1,345 1,326 757

Total coal production 1,608 1,956 2,113 2,325 2,523 2,716 3,050 1,577

Share of railway transportation (%) 55 51 51 48 44 50 44 48


According to NBS statistics, in 2008 56% of China’s coal consumption was in the central, southern and eastern regions, which only produces 33% of coal output. Thus, nearly 25% of China’s coal has to be transported from the north to the south, in many cases a journey of more than 1,000km to its customer base, and mostly going by ocean vessel around the coast.

Railway transportation for coal is tighter in Inner Mongolia than Shanxi, as evidenced by the recent reports of 100km traffic jams from Inner Mongolia to Beijing. Less than half of Inner Mongolias coal is moved by rail, compared to nearly two-thirds from Shanxi.

Figure 102

Figure 103

Shanxi coal transportation

Inner Mongolia coal transportation

Shanxi coal transported by

others39%


railway61%

Inner Mongolia coal transported by

others55%

Inner Mongolia coal

railway transportation

45%


Despite the considerable investment in expanding China’s rail network, the pace of growth in coal production has meant that infrastructure bottlenecks continue to cause problems in moving coal from production bases in the north to consumption centres in the east and south.

The rail network for coal transportation consists of three groups:

North channel - Daqin, Fengshada, Jingyuan, Shenhuang and Tongji (blue lines)

Middle channel - Shitai and Hanchang (green lines)

South channel - Houyue, Taijiao, Longhai, Xikang and Ningxi (yellow lines)

Production growth will be focused on new mining

areas in the west

Rail only carries half of China’s coal

Nearly 25% of coal production is transported

over 1,000km



Figure 104

Current China major coal railway network

Source: MoR, CLSA Asia-Pacific Markets

Figure 105

Coal transportation from the major three channels, history and forecast

(mt) 2008 2009 2010F 2011F 2012F

North tunnel 541 568 662 702 722

Daqin 321 330 400 420 420

Shenhuang 120 143 160 180 200

Fengshada 60 60 60 60 60

Jingyuan 20 20 27 27 27

Jitong 20 15 15 15 15

Middle tunnel 170 170 170 190 190

Shitai 90 90 90 110 110

Hanchang 80 80 80 80 80

South tunnel 190 190 250 250 250

Houyue 120 120 170 170 170

Taijiao 70 70 80 80 80

Total 901 928 1,082 1,142 1,162


Northern channel is most congested and thus has biggest expansion plans



It is the northern corridor which is most congested, and thus the focus of most investment in the rail network and the main area which will see capacity expansion. One key area is the expansion of the Shanxi to Shandong railway, which will allow producers there to bypass some of the busier Bohai basin ports and take coal out from Rizhao, near Qingdao.

The cost for railing on the main Datong-Qinhuangdao line is Rmb0.12 per tonne per kilometre. Shanxi contacts suggested the cost of railing from Shanxi to Qinhuangdao totalled Rmb80-90/tonne for 600km, plus Rmb20-30/tonne port fees. Smaller miners have to pay an additional Rmb40-50/tonne to get access to the rail.

Shanxi is estimated to have no more than 600mtpa capacity to export coal by rail at present, with the rest going by truck into other provinces. Trucking costs have risen in recent years given the crackdown on overloading since 2007 which was destroying the road network.

Trucking is economically viable for moving coal shorter distances, say under 300km, but costs vary a lot by province depending on the number of toll roads and local police enforcement of vehicle loading regulations. Inner Mongolia tends to have the cheapest trucking fees of Rmb0.25-.40/tonne per kilometre, with Shanxi as high as Rmb0.45-0.5/tonne per kilometre. In many cases the transport cost for mines from Shanxi to a coastal power plant is in excess of Rmb300/tonne.

The Ministry of Railway (MoR) expects railway capacity for coal to be raised to more than 1.2 billion tonnes by 2013. It is expected that railway bottlenecks will be greatly reduced from 2014 as many new lines come into operation. Some of the bigger projects aimed at relieving congestion in Inner Mongolia include:

Figure 106

New railways under construction or planned in northeast coal area

Timeframe Note

Jugar to Caofeidian Start construction from 2011 Link Inner Mongolia to Hebei port

Erdos to Machanghao Started construction from Nov 2009 Link railways inside Inner Mongolia

Chefeng to Suizhong Started construction from Jun 2009 Link Inner Mongolia to Liaoning

Chifeng to Jinzhougang To be completed by 2012 Link Inner Mongolia to Liaoning

Xilinhot to Ulanhot Started construction from Oct 2008 Link railways inside Inner Mongolia

Xilinhot to Duolun Link railways inside Inner Mongolia

Ba Yan Siniora to Chu Engadabu Started construction from Jun 2009 Link railways inside Inner Mongolia and to Mongolia

Zhenglan Qi to Zhangbei Start construction from 2010 Link Inner Mongolia to Hebei


Inner Mongolia has plans for three major railways projects: A 256km railway linking Xilin Hot in central Inner Mongolia south to Duolun in the region’s south central area and north of Hebei province, to be built by 2012 and have a freight capacity of 125mtpa; A 247km railway from Zhenglan Qi in central south Inner Mongolia to Zhangjiakou in northern Hebei province, to be completed by 2013 and have a carrying capacity of 30mtpa; A 923km railway from Jining near Hohhot, the autonomous region’s capital, to Tongliao, a terminal city from which other networks connect with Jilin province in northeast China, to be completed by 2014 and have a carrying capacity of 80mtpa.

Smaller miners have to pay a premium to get

access to the rail network

Trucking is economically viable for short distances



Figure 107

Inner Mongolia new railways for coal transportation

Source: MoR, media reports, CLSA Asia-Pacific Markets

The MoR’s long-term target for railway coal transportation capacity is 2.3 billion tonnes, to be achieved through separating passenger and cargo transportation in major rail lines once the addition of high speed rail for passenger services is completed, which will free up existing routes entirely for cargo. The build out of Xinjiang and other western coal railways will also be a major contributor.

Figure 108

China middle and long-term coal railway plan

Source: MoR

Three new rail projects underway in

Inner Mongolia

China’s rail network has major expansion plans



Taxes and trade - Swinging the balance Taxes represent a significant and rising cost for coal mines. As the government has clearly moved to restrict private coal mine production and improve safety standards in recent years, this has encouraged local authorities to levy an increasing number of taxes and fees on the mines.

A resource tax on coal has been speculated about for many years, but most industry players now expect this to be introduced next year, in the first year of the 12th Five-Year Plan. Resource taxes for thermal coal vary by province, but are generally between Rmb2.5-3.6/tonne. The resource tax is widely speculated to be moving to between 3-5% of sales price. The net impact of this move would be to raise costs around Rmb15-20/tonne for thermal mines.

Other charges that mines incur include environmental taxes/sustainable development fund contributions, which in Shanxi are Rmb13/tonne but are likely lower elsewhere. The mineral resources compensation fund is applied nationally at 1% of sales revenue, while the safety fund is charged at Rmb2-10/tonne. The safety fund money is not paid to the government however, but kept by the mine to reinvest in safety equipment. Further additional taxes which are levied by some cities/provinces include relocation compensation expenses, price adjustment funds, city/infrastructure construction taxes and education supplementary taxes. All in all these additional taxes can easily exceed Rmb50/tonne for mines located in a built up or environmentally sensitive area.

In terms of trade taxes, China has gradually increased these over the years to dissuade exports. Prior to 2004, coke, coking coal and thermal coal all received generous tax rebates. After gradually reducing, eliminating, and then introducing export taxes, since 2008 coking and thermal coal have been subject to a 10% export tax, while coke is subject to a 40% export tax.

Figure 109


Thermal coal Pre 2004 13% export rebate January 2004 11% export rebate January 2005 8% export rebate September 2006 export rebate removed August 2008 10% export tax

Figure 110

Chinese export quota changes

(mt) Coal export quota

Actual coal exports

Coke export quota

Actual coke exports

2003 100 94 12 2004 80 87 13 162005 80 72 14 132006 80 63 14 142007 70 53 12 152008 48 45 12 122009 51 22 12 12010 1st batch 26 1Q-3Q 15 1st batch 4 1Q-3Q 2Source: Media reports, Ministry of Finance, CLSA Asia-Pacific Markets

Not only are these taxes a significant barrier to export volumes, but the trend of rising taxes over time clearly illustrates the Chinese government’s rising desire to not be a serious exporter of low value, highly polluting products.

Taxes have increased a lot

Resource tax likely to be introduced

Additional taxes are payable

China’s coal trade taxes have moved

against exports



Should exports of coke or coals become attractive in the future, we would expect to see further tax hikes to make it unattractive again. Consequently, we have very little in the way of exports of any coal products from China in our forecasts.

In total we look for Chinese thermal-coal production to grow only 3% pa for the next five years. This growth rate will require imports to more than double to 255 million tonnes in 2015.

Figure 111

Import penetration - Base case

(mt¹) 2008 2009 2010 2011 2012 2013 2014 2015


South/east coast consumption 301 319 347 366 377 397 398 400


Coal imports 34 92 119 130 150 180 230 255

Coal exports 43 22 19 10 5 5 5 5



¹ Numbers refer to washed coal. Source: CLSA Asia-Pacific Markets

India - Plenty of coal but not the best quality India is the third-largest coal-producing country in the world, with most production in the central eastern area. It has the world’s fifth-largest reserves, of which 86% are contained in only five provinces. Only 13% of the reserves are coking coal, which are generally of low quality, hence the need for imports.

Figure 112

Geological resources of coal (mt)

State Proved % of total

Indicated % of total

Inferred % of total

Total % of total

Andhra Pradesh 9,194 8.7 6,748 5.5 2,985 7.9 18,927 7.1

Arunachal Pradesh 31 0.0 40 0.0 19 0.1 90 0.0

Assam 348 0.3 36 0.0 3 0.0 387 0.1

Bihar 0 0.0 0 0.0 160 0.4 160 0.1

Chhattisgarh 10,910 10.3 29,192 23.6 4,381 11.6 44,483 16.6

Jharkhand 39,480 37.3 30,894 25.0 6,338 16.7 76,713 28.7

Madhya Pradesh 8,041 7.6 10,295 8.3 2,645 7.0 20,981 7.9

Maharashtra 5,255 5.0 2,907 2.4 1,992 5.3 10,154 3.8

Meghalaya 89 0.1 17 0.0 471 1.2 577 0.2

Nagaland 9 0.0 0 0.0 13 0.0 22 0.0

Orissa 19,944 18.8 31,484 25.5 13,799 36.4 65,227 24.4

Sikkim 0 0.0 58 0.0 43 0.1 101 0.0

Uttar Pradesh 866 0.8 196 0.2 0 0.0 1,062 0.4

West Bengal 11,653 11.0 11,603 9.4 5,071 13.4 28,327 10.6

Total 105,820 100.0 123,470 100.0 37,920 100.0 267,212 100.0

Source: Ministry of Coal, CLSA Asia-Pacific Markets

India lacking in quality coal

Slower domestic production will

encourage imports



Figure 113

Break-up of production between coking and non-coking coal

376 399 423458

488

3232

3435

44

0

100

200

300

400

500

600

FY06 FY07 FY08 FY09 FY10

Non-coking Coking(mt)

Figure 114

State-wise production of coking and non-coking coal

(mt) FY06 FY07 FY08 FY09 FY10 % of totalCoking Chattisgarh 0.2 0.2 0.2 0.1 0.2 0.3Jharkhand 30.3 31.1 33.6 33.9 43.5 98.3Madhya Pradesh 0.9 0.8 0.7 0.7 0.5 1.2West Bengal 0.1 0.1 0.1 0.1 0.1 0.1Total 31.5 32.1 34.5 34.8 44.3 100.0Non coking Andhra Pradesh 36.1 37.7 40.6 44.5 50.4 10.3Arunanchal Pradesh 0.1 0.1 0.3 0.1Assam 1.1 1.1 1.1 1.0 1.1 0.2Chattisgarh 76.2 83.1 90.0 101.8 109.8 22.5J&K 0.0 0.0 0.0 0.0 0.0 0.0Jharkhand 55.1 57.7 57.3 62.4 62.4 12.8Madhya Pradesh 54.6 59.0 67.2 70.6 73.5 15.1Maharashtra 36.1 36.2 36.4 38.7 41.0 8.4Meghalaya 5.6 5.8 6.5 5.5 5.8 1.2Orissa 70.5 81.2 89.5 98.4 106.4 21.8Uttar Pradesh 15.7 12.2 11.4 12.0 14.0 2.9West Bengal 24.3 24.9 22.5 22.8 23.1 4.7Total 375.5 398.7 422.6 457.9 487.8 100.0


According to data provider Credit Rating Information Service of India, 46% of coal in India is moved by rail, with the remainder moved by truck or sea routes. Coal is the largest single commodity carried by Indian Rail, but has a preferential tariff rate. This is the opposite of iron ore, for which Indian Rail charges a very high tariff rate in order to take its “fair share” of the profits from exporting iron ore. Coal transportation is closely linked to iron ore exports, as in many cases the rake (railcars) which are used to export iron ore from mine to port, are then used to bring coal in from that port to a local power station, before returning to the iron-ore mine.

As the future trends will be towards less iron-ore exports and more coal imports, we expect the preferential tariff which coal currently benefits from in India will be increased more in line with general market rates.

Over 90% of India’s coal production is thermal

Coal production is concentrated in five states

Indian rail capacity cannot meet demand for

coal transportation



Indian Rail is seeing significant investment levels presently. The flagship investment is the golden quadrilateral linking Delhi, Kolkata, Chennai and Mumbai, covering a distance over 2,000km. More importantly for coal transportation will be improved links between ports, mines and the cities which are seeing growing power demand, for which 2,800km of rail track is now being laid.

India is also seeing investment of Rs1tn in ports, with 387 projects identified under the National Maritime Development Programme.

Mining costs in India are cheap compared to elsewhere in the world. Given the abundant reserves, nearly 90% of India’s coal production comes from open-pit mines. These have an operating cost of no more than US$15/tonne (Rs600/tonne), though according to Coal India there has been significant cost inflation in the past four years, of about 25% over that timeframe. Underground mining costs are significantly higher, up to US$80/tonne, but most underground mines are coking coal and hence are still economically viable.

Coal India is the largest coal supplier in India and in the world. It supplied 295 million tonnes to the power sector in FY10 against the target of 312 million tonnes in FY10.

Most thermal-coal power generation expansions are relying on Coal India to supply their coal, but this is likely to disappoint. Some 74% of projects under the 11th Five-Year Plan are depending on coal linkages from Coal India. Thus, we might see coal shortages in the coming years which will either lead to lower utilisation rates of power projects or higher imports which implies a high power tariff or a mix of both.

Figure 115

Sources of coal for capacity addition under in the 11th Five-Year Plan

Linkage74%

Imported coal13%

Captive coal13%


The alternative which a number of power plants are relying on is to develop their own captive coal blocks. However, progress on these, even after securing an allocation which itself takes years, has been extremely slow to date. Securing land acquisition and gaining local permits for mine developments and related infrastructure are the main barriers to development of captive coal blocks. Of the 122 coal blocks allocated since 1993, only 20 are now in operation.

Coal linkages remain the dominant source of fuel

Considerable investment in ports means there

won’t be a bottleneck

Coal India is the largest coal miner in the world



Figure 116

Sources of coal for capacity addition in the 11th Five-Year plan

400

500

600

700

800

900

1,000

2010 2011 2012 2013 2014 2015

Non-coking coal demand

Non-coking coal supply

(mt, y/e March)


Figure 117

Status of coal blocks allocated

Year No. of blocks

allocated

Target yearof starting production

No. of blocks that have started

production

Pending milestones

1993- 2003

40 1996-2007 20 Forest clearance, land acquisition and environment management plans

2004 5 2008 0 Land acquisition and forest clearance

2005 24 2008-11 0 Forest clearance, land acquisition and environment management plans

2006 53 2009-12 0 Prospecting licence not yet granted in many cases. Almost all lagging on timelines

Source: Coal India, CLSA Asia-Pacific Markets

By the end of the 11th plan the captive coal blocks are expected to contribute 80mtpa of coal. However, given the lack of progress on most of the blocks it is expected that their contribution will be only about 42 million tonnes. Even that target will be hard to reach, and over the next two years we only expect the supply of coal to the power sector from the captive blocks is likely to remain at 22 million tonnes for the next two years.

It is this lack of potential for growth in domestic coal supply which drives our forecast for thermal-coal imports in India. We forecast domestic coal production to grow at a healthy pace of 6.9% through to 2015, but this production expansion will still require imports to see its share of Indian coal consumption grow from 12% in FY10 to 26% in FY11, or 189 million tonnes.

Figure 118



Demand 426 451 542 603 657 711

Domestic supply 374 387 432 473 489 522


Coking coal - All about Australia Coal has been a major part of Australia’s exports for decades. Australia supplies 60% of the seaborne coking-coal market. With abundant reserves and numerous mining companies active in the country, the only barrier to higher exports from Australia in recent years has been infrastructure. Unlike the major iron ore ports, which are run by individual producers and thus an integrated part of their entire supply chain, the coal ports and rail networks in Queensland and New South Wales are mostly run by local authorities or have shared ownership.

Coal is a major part of Australia’s exports



Domestic supply will struggle to keep pace

with demand

Imports will fill the domestic supply deficit

Captive coal mines will struggle to be built



Figure 119

Map of main global coking-coal supply

Source: Teck, McCloskey

Infrastructure bottlenecks have been plaguing Australia’s coal industry over the past few years. Governments and the sector had underestimated the strong surge in demand for coking and thermal coal in Asia. Major coal ports of Dalrymple Bay and Newcastle have seen queues of up to 100 ships over the past three years. Although port delays eased in 2009, it was largely a result of demand-related decrease in export volumes. In early 2010, a recovery in demand led to queues expanding again, with up to 60 ships at Dalrymple Bay and lengthening lines at Newcastle.

There is light at the end of the tunnel, with some expansion plans nearing completion. The first stage of a new coal terminal at Newcastle (NCIG) was commissioned earlier this year. An expansion at Dalrymple Bay was also completed in the past year, although rail bottlenecks continue to restrict export volumes there. Ramp-ups are underway at Newcastle, Brisbane and Gladstone, while the approval of the Northern Missing Link by the Queensland government should pave the way for a major port expansion at Abbot Point over the next two to three years.

Despite these impressive developments, infrastructure bottlenecks will continue to constrain coal exports from Australia. The industry’s production forecasts continue to exceed available rail and port capacity. Project delays seem inevitable despite stronger-than-ever demand for Australian coking and thermal coals. Queensland and NSW still need to invest a significant amount on rail and port infrastructure to meet the production aspirations of miners.

Queensland is key for coking coal Queensland supplies over 80% of Australia’s coking-coal exports, and nearly 60% of the global seaborne market. Australian metallurgical coals consist of hard coking coal, semi-soft and semi-hard coking coal, and PCI coal. Asian countries dominate the export sales of these resources, with Japan, Korea, Taiwan, China and India accounting for nearly 80%.

Railways State-owned Queensland Rail (QR) operates Queensland’s rail network. It owns the infrastructure and has a dominant position in coal haulage in the state. However, having commenced haulage operations in Queensland and won a number of significant haulage contracts, Pacific National is challenging QR’s leading position.

Rail and port bottlenecks have subdued exports

Completion of new infrastructure projects

Further investment needed to meet mine-

expansion plans

Queensland accounts for 80% of Australia’s coking

coal exports

Queensland Rail is the dominant player

Known potential sources of new supply necessary to meet forecast demand

are limited and challenged



The Queensland government has commenced a sale process for the QR assets, which could result in either an IPO, or an asset sale to an industry or financial investor.

Queensland’s rail infrastructure has capacity of about 224mtpa, comprising five separate rail systems. The proposed Northern Missing Link and Surat Basin Railway will further extend and connect the current network. The most significant systems are Goonyella and Blackwater.

Goonyella accounts for more than half of all transported coal tonnages in Queensland and is used by all the major industry participants, including BHP Billiton Mitsubishi Alliance (BMA), Xstrata Coal, Anglo Coal, Peabody Pacific, Rio Tinto and Macarthur Coal. Goonyella primarily delivers coal to the Hay Point and Dalrymple Bay coal terminals. It also supplies modest tonnage to the Abbot Point terminal. The proposed Northern Missing Link will enable significant increases in tonnage to Abbot Point on the Goonyella rail system by linking it with the Newlands system.

The Blackwater system is the second-largest rail-haulage system in Queensland. It delivers coal into the RG Tanna and Barney Point terminals in Gladstone and will also service Wiggins Island once it is constructed. Major users of the system include BMA, Rio Tinto, Xstrata and Wesfarmers.

Figure 120

Queensland Rail - Coal throughput and forecast capacity

(mt) 2005-06 2006-07 2007-08 2008-09 12-13CL 13-15CL 15CL+

Blackwater System 45 50 52 51 70 83 107Moura System 10 12 12 11 15 31 41

Goonyella System 82 88 83 87 145 186 228Newlands System 11 11 12 14 50 80 105

Western System 5 4 6 6 10 13 14Surat (proposed) 42 67

Total 154 165 164 169 290 435 495

Note: June year-end. Source: QR 2009 Master Plan, CLSA Asia-Pacific Markets

Ports Dalrymple Bay Coal Terminal (DBCT), Hay Point Coal Terminal (HPCT), Abbot Point Coal Terminal (APCT) and the RG Tanna Coal Terminal at Gladstone handle a majority of Queensland’s coal exports. DBCT is operated by Prime Infrastructure, HPCT by BHP Billiton Mitsubishi Alliance (BMA), APCT by Xstrata and RG Tanna by the state-owned Gladstone Ports. Queensland’s coal export capacity is likely to increase from 192 million tonnes in 2010 to 217 million tonnes in 2011. A majority reflects expansions at HPCT and APCT. DBCT has a stated capacity of 85mtpa, but we believe infrastructure and design constraints are likely to see capacity limited to 68mtpa.

In the medium term, the bulk of port-capacity growth is likely to come from APCT and Wiggins Island. An expansion to 25mtpa took place at APCT in mid-2009 and a doubling of capacity to 50mtpa is due to come on stream in mid-2011. Further ramp-ups to 80mtpa and 110mtpa are planned but will require significant investment in rail infrastructure, which is unlikely to occur until the privatisation of QR is completed. The expansion to 110mtpa will probably cost upwards of A$4bn and completion is unlikely before 2015.

The state government plans to privatise QR

Five rail systems have a combined

capacity of 224mtpa

Tonnages on Blackwater will increase once

Wiggins Island is built

Four major export ports in Queensland

Expansions planned at APCT and Wiggins Island

All major coal players use Goonyella



Wiggins Island Coal Terminal (WICT) is a new development at Gladstone. Development will be in three stages. Stage 1 will have 25mtpa of loading capacity with the subsequent Stage 2 and Stage 3 expansions lifting loading capacity to 70mtpa. Cost of the expansion will be about A$3.0-4.0bn. Completion of the first stage is likely to occur in 2012-13.

Capacity forecasts Port capacity constrains coal exports in Queensland, although it could be argued that the inefficiencies at Dalrymple Bay are more related to both port and rail design limitations. Post 2014, completion of the APCT expansion and the new WICT will place significant pressure on rail infrastructure, even though QR’s current forecasts suggest that rail capacity will continue to outpace port capacity. An acceleration of the 110mtpa expansion at Abbot Point or a delay in the privatisation of QR could see rail become the bottleneck.

Figure 121

Queensland’s coal rail and port capacity

0

50

100

150

200

250

300

350

400

450

500

08/09 09/10 10/11 11/12 12/13 13/14 14/15 15/16

(mtpa) Port Capacity Rail Capacity

Source: Queensland Rail, Gladstone Ports, Ports Corporation of Queensland, CLSA Asia-Pacific Markets

Costs - Mining costs very competitive but capex is rising Coal production costs in Australia on an FOB basis are very competitive in the world market as three-quarters of production comes from open pit mines. Coking coal costs average about US$70/tonne FOB, given their generally higher stripping ratios than thermal coal.

A significant barrier to rising investment in coal capacity in Australia is the rapid appreciation in capex costs in recent years. While there was a pause in investment in 2008 amid the financial crisis, investment in coal and iron-ore projects in Australia is back at record highs, and this is resulting in significant cost inflation for labour, materials and contractors, while the appreciating Australian dollar means costs for mine expansion in US dollar terms is now significantly higher than almost anywhere else, for most Greenfield mines in excess of US$100/tonne of capacity, and that’s excluding port infrastructure.

Despite Australia’s very competitive position in terms of resources and geographical proximity to Asian markets, expansions in coal exports will be substantially slower than for iron ore due to the lack of captive logistics. Miners have to be patient with the slow pace of growth in publicly owned infrastructure, which will remain the limiting factor in exports for the foreseeable future.

WICT could be expanded to 70mtpa

Port capacity remains the limiting factor

in the long term

Risks: acceleration of Abbot Point expansion or

QR privatisation delay

Australian mining costs are among the lowest in

the world

Capex costs are rising rapidly

Public ownership of infrastructure will slow

expansion growth



We foresee total Australian coking-coal exports rising only 20% over the next five years. There are no significantly large projects contributing to this growth, rather all suppliers are increasing their exports by a few million tonnes. PCI exports will rise 40% over the period, with HCC up 20% and semi-soft up 15%. BHPB/Mitsubishi alliance will maintain a steady 55% share of Australian HCC exports through 2015.

Figure 122

Figure 123

Coking-coal export share, 2010

Hard coking-coal export share, 2010

Rio Tinto8%

Xstrata11%

Anglo12%

Other31%

BMA38%

Other6%

Peabody7%

Gujarat2%

Anglo11%

Xstrata10%

Rio Tinto11%

BMA53%

Figure 124

Figure 125

Coking-coal export share, 2015

Hard coking-coal export share, 2015

Xstrata9%

Rio Tinto9%Anglo

11%

Other37%

BMA34%

Other10%Peabody

8%

Gujarat5%

Anglo10%

Rio Tinto10%

Xstrata9%

BMA48%


With capacity growth split between the producers, the main downside risks to export volumes comes from any delay to the infrastructure plans, rather than any individual mine expansions.

North America - Highest cost seaborne supplier The US coal industry has had some rocky times over the last several years as oversupply in the steam market has put a damper on prices only being offset on the positive side by higher coking-coal prices. Coking-coal exports from the USA have risen strongly in 2010 as weak domestic steel production has allowed suppliers to switch capacity to the export market, incentivised by high seaborne prices. While coking-coal production costs in the USA are among the highest in the seaborne market, our forecast of sustained prices above US$200/tonne for the next few years will incentivise increasing exports from the USA as a number of producers bring on small capacity expansions.

Canada has struggled to raise exports in recent years, but capacity expansions at the major producer Teck, combined with a few smaller expansions at other producers, will see Canadian coking-coal exports rise 50% over the next five years.

Coal production, exports Total coal production in the US for 2010 is expected to be approximately 1bn tonnes, down almost 10% from 2008 levels. We see incremental coking-coal production coming on line, from companies like Walter Energy and Teck Resources in 2011, but for the most part the incremental coking-coal supply

US coking-coal costs are high, but exports have been

incentivised by high prices

US coking-coal exports are constrained by logistics

Coking coal exports will only rise 20% through

2015

BMA has the largest share of coking coal exports

Market shares won’t change much through 2015

Canadian exports will rise 50% in the

next five years



will be to replace depleted mine production and will come from cross over tonnes. We look for a continued tight market as production remains constrained and North American exports of coking coal are maintained. Coking-coal exports in 2010 are expected to be around 50 million tonnes in 2010 excluding Canada. We believe that exports above 60 million tonnes could be limited for coking coal due to port limitations.

Figure 126

Supply and demand

(mt) Production Consumption Net exports

East West Total Utility Coking Other Total Imports Exports

Net exports

Coking coal(included in

exports)1980 573 251 824 569 67 67 703 1 92 911985 559 325 884 694 41 83 820 2 93 911990 630 399 1,029 781 39 83 903 3 106 1031995 542 491 1,033 850 33 79 969 7 89 812000 510 565 1,076 995 29 70 1,094 13 58 46 332001 526 596 1,121 973 26 67 1,066 20 49 29 252002 489 601 1,090 978 24 65 1,066 17 40 23 212003 468 601 1,069 1,005 24 66 1,095 25 43 18 222004 485 627 1,112 1,015 24 66 1,105 27 48 21 272005 493 640 1,133 1,039 23 66 1,129 30 50 19 292006 491 668 1,159 1,026 24 66 1,116 37 49 12 282007 482 664 1,147 1,045 22 61 1,128 37 59 22 322008 492 678 1,170 1,042 22 58 1,122 34 83 49 432009 458 627 1,086 943 14 51 1,008 23 59 36 372010CL 444 632 1,076 997 20 53 1,070 19 80 61 582011CL 455 660 1,115 1,007 20 53 1,080 22 82 60 602012CL 460 670 1,130 1,017 20 53 1,090 23 85 62 60Source: EIA, Credit Agricole (USA)

Environmental impact The EPA has issued a statement blocking Arch Coal’s Spruce mine. The controversy stems from the Clean Water Act which prevents companies from discharging rock, dirt or other debris into streams and rivers unless it can be proven that it will not cause permanent damage to the waterway or surrounding ecosystem. The EPA has the authority to review and veto any permit granted by the Corp of Engineers, but until recently has rarely exercised the right. This potentially could impact all surface production in Central Appalachia, which equates to around 120 million tonnes (half of 2008 CAPP production). This decline in production will not come in one fell swoop, but over time. Costs will rise for company’s in the region as they have to go underground to continue to produce coal in the region.

Costs US coal costs are relatively high on an FOB basis. Mining costs are higher than world averages given that many mines are old and suffering from rising stripping ratios. High labour, energy, safety and environmental costs also contribute to the higher cost base. Logistics costs are a significant barrier to higher export volumes, as in many cases these outweigh mining costs.

US coking-coal exports are the highest cost seaborne supply into Asia, with some of the smaller mines having a total cost of US$150/t CFR China after adjusting for quality. A significant proportion of this cost comes from infrastructure, as coal production is concentrated in the centre of the country.

Increasing environmental pressures will limit

export growth

Infrastructure is a major cost

US coal-production costs are high



Canada is the world’s third-largest metallurgical coal exporter. Despite its considerable railing distances, large scale Canadian coal costs on an FOB basis are more competitive that the smaller US mines, at about US$80/tonne FOB, or under US$120/tonne CFR China. Mine expansions in Canada are not logistically constrained, and there is potential for producers there to respond to higher prices with further expansions beyond current plans.

CIS - Struggling to grow Russia produces more than 300mtpa of coal, and has 20% of global coal reserves, or 157 billion tonnes, according to the BP statistical review. Russia accounts for fewer than 5% of seaborne coking-coal exports as most sales are overland. While CIS countries are significant producers of coal, for the purpose of this report we are only interested in coal shipments into the globally traded market.

Russian exports have been growing at no more than 3% pa in recent years, and last year totalled 15 million tonnes for coking coal, half of which is hard coking coal. Most of Russia’s exports go to Ukraine, Turkey and Europe, with 15-20 million tonnes going by rail. Given that most demand growth for coal is in Asia, the Russian east coast ports are the main growth focus these days. Exports are likely to reach 30 million tonnes from its east coast ports this year, with about six million tonnes of this being coking coal.

Figure 127

Russian coal exports by port

(mt) 2008 2009 10CLFar East 20 26 30Baltic & Northern 43 48 32Black Sea 24 20 22Total 87 95 83Source: Metaldata, CLSA Asia-Pacific Markets

Mining costs in Russia are quite high given that three quarters of mines are underground, while the extremely long distances on the Trans-Siberian railway, given most of the mines are in the centre of the country, makes their total FOB cost relatively high. At the beginning of 2010, the government raised rail tariffs for coal by 9.4%.

Even if miners can afford the high rail tariffs, the rail network is the main bottleneck for exports according to miners. Railing from mines in the western areas to export to Europe via rail or ports has reasonable capacity, but trying to rail coal to the east coast ports is very capacity constrained. Additionally there is little investment planned by the government in expanding the Trans-Siberian railway, so the situation is unlikely to improve soon.

Another cost disadvantage for the Russian coal exporters is that their ports are generally shallow draft, meaning they can only use small vessels. This makes it prohibitively expensive to export coal from west coast ports to Asia, though given the geographical proximity of east coast ports to north Asian markets, it’s not a significant disadvantage for east coast exports.

The only significant growth in Russia’s exports is likely to come from Mechel’s Elga coking-coal deposit. Mechel has constructed their own rail spur line, and controls their own port on the east coast, which should enable their new mine to reach its planned 9mtpa export capacity by 2014. Apart from the Mechel project, we do not expect to see much growth in Russian coking-coal exports in coming years.

Russia accounts for only 5% of seaborne coking

coal trade

Lack of rail capacity constrains exports

Most Russian ports are shallow draft

Exports have only grown slowly in recent years

Canada is the third-largest met coal exporter

East coast ports have seen the most growth,

driven by Asian markets

Russian costs are high, driven by infrastructure

Mechels Elga mine will provide all the growth in

coking coal exports



Mongolia - New supplier but captive to China? For the next few years Mongolia will largely be a coking-coal story. Mongolia has an estimated 12.1 billion tonnes of coal reserves, of which two billion tonnes are coking coal. Despite its geographical proximity to China, logistics costs for Mongolian exports are high, and given that Inner Mongolia is China’s largest thermal-coal-producing province, then until there are significant infrastructure improvements, there is little competitive advantage for Mongolia to export thermal coal to China. About 80% of Mongolia’s coal exports to China in 2010 will be coking coal, but only 50% hard coking coal. Tavan Tolgoi is the only deposit providing HCC at present, which should export about seven million tonnes to China this year from MCC and Energy Resources.

Mongolia currently has five main operating coal companies, with South Gobi and MCC the only listed ones of the five. Total Mongolian coal exports over 1H were reported at 7.9 million tonnes, though Chinese import data suggests a figure of 6.9 million tonnes. Mongolia surpassed Australia as China’s largest supplier of coking coal in June 2010, and volumes continue to grow at a significant pace. Mongolia will export about 15 million tonnes of coking coal to China in 2010, accounting for 40% of China’s coking-coal imports. Mongolia has about 20 million tonnes of coking-coal production capacity, and this will rise to 60 million tonnes by 2015. However, logistics will be the main barrier to this growth, as all of Mongolia’s coal exports enter China by truck, so rail capacity is much needed on both sides of the border.

Given that most of Mongolia’s coal deposits currently being mined are close to the surface, this supports large scale open pit mining, which means it’s absolute mining cost is very cheap. CRR estimates average mining costs are around US$15-17/tonne, around half the mining costs in China. However, all coal from Mongolia is currently sold in raw, unwashed form, as the lack of water in the country means washing coal is economically infeasible. MCC has plans to construct a washing plant based on ground water, and given its scale and recent fund raising it may work, but the other producers are unlikely to be successful in following with similar developments. Shipping unwashed coal raises the overall coal cost as the logistics costs to the wash plant, the main one being 150km into China are thus included in the yield loss in washing.

Rail infrastructure, or lack of it, is the major barrier to faster growth in Mongolian coal exports. Until extensive rail networks are built out, Mongolian coal producers remain at the mercy of a handful of buyers given their lack of sales options. Trucking coal is about three times more expensive than railing it, so the lack of rail capacity also pushes Mongolian coal up the cost curve.

CRR survey work shows that it costs around US$20/tonne to truck coal from the Tavan Tolgoi mining area to the Ganq Mod border crossing, a distance of only 255km. Even trucking only 50km, such as from the Narlin Sukhait mine to the Ceke border crossing, costs US$6/tonne. Mongolian border fees are around US$2.90/tonne, however China customs fees and other costs bring the total to US$17/tonne.

The Mongolian government has recently announced a decision to build a 450km Russian guage rail from the large Tavan Tolgoi coal deposit to link with the sole existing rail line at Saynshand. This decision comes as a disappointment to the Chinese, who were hoping for a more direct 250km rail line into China, which would also have passed Ivanhoe’s Oyu Tolgoi mine.

Mining costs in Mongolia are low, but there are no

washing facilities

Border crossing fees are also high

Most of Mongolia’s exports are coking coal

Mongolia recently displaced Australia as the largest source of China’s

coking coal imports

Rail infrastructure is lacking, so trucking is the

only (expensive) option

Mongolian government to continue building

Russian rail



Figure 128

Mongolia map and railway

Source: map website

Politically the Mongolians are used to balancing the interests of the Russians and the Chinese, and don’t want to be too reliant on either. While almost 80% of Mongolia’s exports go to China, 90% of Mongolia’s oil is imported from Russia, together with 30% of its power needs. The Russians already own 50% of the existing rail line and are keen to be involved in any expansions. Another idea recently suggested by the Mongolians is to build a further rail link to northwest Mongolia and into Russia, in order to give rail access to Russia’s Far Eastern ports, and the option to export to Japan and South Korea, though the near 2,000km rail journey would not be cheap. The Mongolians are keen to develop as much optionality for their exports as possible, in order to ensure the Chinese pay close to market prices for their exports, rather than being the sole sales option. The Mongolians have bad memories of the Chinese closing the border in 2002, and giving preferential treatment to Chinese cargos over Mongolian ones on the rail network.

This recent decision to build further Russian gauge rail, which is wider and incompatible with Chinese gauge rail, doesn’t rule out the prospect for more direct rail links into China. If anything the latest announcement is more to do with the political manoeuvring around the construction of Chinese gauge rail, to try and encourage the Chinese into offering more investment in the Mongolian economy, as the Mongolians are keen to add value and industrial capacity within Mongolia, rather than just providing basic resources for China.

Once the coal enters China, to reach most steel mill customers it has to be transported through one of the most congested areas in China’s rail network to get to Qinhuangdao port. There are currently only two border crossings which handle coal, though another three are under construction, all of which will be majority owned and operated by Winsway.

Currently, coal from the Gang Mod border crossing is trucked 150km for a US$10 cost to the Winsway washing plant, where after processing it is trucked another 150km to the nearest rail head in Baotou. From there the coal takes a 1,100km rail journey to Qinhuangdao, at a cost of US$45/tonne. Port handling fees plus shipping costs total US$20/tonne delivered to Shanghai. Baosteel estimates the total cost of transporting Mongolian coal to its steelworks in Shanghai is US$140/tonne, but that includes profit margins

Mongolia is used to balancing the influences

of Russia and China

Chinese rail could still ultimately be built

Transport of Mongolian coal to Chinese ports

is expensive

Total delivered costs to Shanghai are over

US$155/t

Infrastructure is very sparse in Mongolia



for various players through the supply chain. Nonetheless, with the current lack of rail infrastructure, we estimate the total cost of Mongolian coking coal on a delivered Shanghai basis at US$155/tonne.

Figure 129

Mongolian delivered costs to Chinese steel mill

0 20 40 60 80 100 120 140 160

Mining

Truck 1

Border fees

Truck 2

Washing

Truck 3

Rail to port

Port fees

Shipping

Port fees

(US$/t)

Source: Queensland Rail, Gladstone Ports, Ports Corporation of Queensland, CLSA Asia-Pacific Markets

In China’s Inner Mongolia, three new rail projects began at the end of August. The three projects are located in the east of the province, and will contribute to reducing congestion for coal exports to Hebei and Caofeidian port. The province badly needs new infrastructure as its coal production has risen at a phenomenal pace. Production in 2010 will near 700 million tonnes, up from under 300 million tonnes in 2006. The recent traffic jam which saw trucks queuing for 100km from Inner Mongolia to Beijing was largely caused by the volume of trucks carrying coal for which there was no space on the rail network.

While much of the rail capacity build out in Inner Mongolia is focused on carrying domestic coal, there are some projects underway which will provide rail access near the Mongolian border. Northwest of Baotou, in central Inner Mongolia, a rail line is under construction which will reach the Mongolian border south of the major coal deposit at Tavan Tolgoi.

Further west, a rail link is also under construction which will extend near the border south of the deposit mined by South Gobi and MAK. Once completed, this should reduce trucking costs for those producers by about US$25/tonne as they save an 800km truck journey to the existing rail head. Until significant rail infrastructure is in place on both sides of the border, Mongolia will struggle to fulfil its potential for coal exports. See the China thermal-coal supply section for more details on China’s rail capacity build out.

An additional negative for Mongolian coking coal is that it generally trades at a VIU (Value in Use) discount. It has lower volatility and higher porosity, but generally has a higher ash content than good Chinese or Australian coal. Mongolian thermal coal only averages a 5,000kcal/kg calorific value, which means it is poorly placed to compete with Chinese thermal coal, though as Chinese grades deteriorate and logistics options improve, Mongolia could become a significant source of thermal coal later this decade.

An upside risk to coal export volumes from Mongolia could come from a trade treaty which greatly reduces customs and other tariffs at the border, and allows for more seamless exports. Should this occur, it could reduce Mongolian coal costs delivered to China by up to US$15/tonne.

Logistics account for most of the cost of Mongolian

coal to coastal mills

Inner Mongolia is expanding rail capacity

Inner Mongolian rail will ultimately connect to

the border

Closer cooperation between Mongolia and China could

lower border fees

Mongolian coal also suffers from a VIU

discount

More rail will reduce logistics costs



Mozambique - The great hope for coking coal Mozambique has seen significant investment in coking-coal projects over the past few years. Riversdale and Vale will begin production from their coal mines in late 2011, while Coal India and others are also actively assessing projects in the country.

The countries infrastructure is in a pretty poor state after the country was ravaged by civil war for over a decade prior to 1992, but upgrades are well under way over the +600km line from the mines in Tete province to the port at Beira. Significant additional investment in infrastructure will be needed for producers to achieve planned exports above their first stage expansions, but given the profitability of the mines and amount of investment already undertaken, we wouldn’t expect there to be too many difficulties in building this infrastructure.

Mozambique is competitively positioned to become a major coking-coal exporter. The Tete province is undeveloped with the “low hanging fruit” unpicked. Coal deposits, which consist of layers of thin seams at very low strip ratios, should enable low cost mine development to be undertaken in country, more than offsetting the higher infrastructure and coal transport costs. The low strip ratios and flat lying nature of the coal seams have enabled both Riversdale and Vale to report large coal resources and reserves. Additionally, the country’s location on the southeast coast of Africa makes it the closest supplier to India. It is also well positioned to ship to Brazil, as many empty ships move past the country heading from the Pacific back to the Atlantic market to pick up Brazilian iron ore for shipment into Asia.

China - Lacking in hard coking coal China is by far the world’s largest coal producer, and has reserves of over 1.1 trillion tonnes, but only about 20% of this is coking coal. China is however lacking in low volatility, high-fluidity hard coking coal. Wood Mackenzie estimates total economic coal resources in China to be 221 billion tonnes, with only 22% being coking coal.

Figure 130

China coal reserve by province

Basic coal reserve (bn tonnes)National total 326.1Shanxi 106.2Inner Mongolia 78.9Shaanxi 27.8Xinjiang 14.7Henan 11.6Anhui 8.6Yunan 7.9Hebei 6.1Gansu 6.0Ningxia 5.8Sichuan 5.0Qinghai 2.0Hunan 2.0Jiangsu 1.5Guangxi 0.8Jiangxi 0.8Beijing 0.7Hubei 0.3others 39.5Source: CEIC, CLSA Asia-Pacific Markets

Only 20% of China’s reserves are coking coal

Mozambique is a big focus of investment

Infrastructure needs a lot of investment

Mozambique is competitively positioned

China’s reserves are concentrated in the north

and west



In 2009 China produced 2.7 billion tonnes of coal, of which 18% was coking coal. Shanxi provides the vast majority of China’s coking-coal output. The consolidation efforts in Shanxi are the main factor causing a rise in China’s imports for coking coal, especially hard coking coal.

Figure 131

Figure 132

China coal output by type

Shanxi coal output by type

Thermal coal63%

Coking coal37%

Thermal coal

49.8%

Coking coal

50.2%


Between 2000 and 2008 Chinese coking-coal mines, mostly in Shanxi, were able to keep up with demand from a booming steel industry that saw steel production rise from 129 million tonnes in 2000 to over 500 million tonnes in 2008. Since 2008 however, China’s coking-coal output has struggled to grow further.

The consolidation process and drives to improve mine safety in Shanxi has seen many small mines there close. The number of mines in the province has been reduced from more than 4,500 to only 1,053, of which 136 are SOEs and 927 are local mines, of which 30% of those are truly private and the rest have mixed ownership. Output from small and medium mines has declined from over 30 million tonnes per month in 2007 to only 22 million tonnes per month in 1H10. The minimum size for the mines post consolidation is about 300ktpa, and most of the still operating small mines are relatively new ones which were built to a decent safety standard.

Figure 133

Shanxi coal mine consolidation

0

200

400

600

800

1,000

1,200

1,400

2003 2004 2005 2006 2007 2008 postconsolidation

(mtpa)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000(No.)Capacity (LHS) No. of mines

Source: Fenwei, CLSA Asia-Pacific Markets

Recent visits to Shanxi give the impression that mine output will recover in the coming years, albeit at rather a slow pace. The SOE consolidators complain that with so many small scale, often illegal, mine shafts scattered around the now consolidated large deposits, the new owners are struggling to come up with

Chinese coking-coal supply supported steel production

up to 500 million tonnes

Some deposits have been ruined and will struggle

to be mined

Shanxi produces most coking coal

Half of Shanxi production is coking coal

Number of mines in Shanxi has been sharply reduced

Capacity is planned to grow post consolidation



viable mine plans. In many cases the remaining deposit looks like Swiss cheese with multiple holes through the best bits, so the SOE owners are unlikely to even try to restart production from some deposits as it looks unsafe to do so.

In terms of Chinese costs, these have already jumped by over 30% in the past two years as the rising focus on safety and environmental issues have combined with a need for mines to go deeper and deeper underground into more complex geology as resources are increasingly consumed. Some mines now extend so deep and wide that it takes miners up to two hours to get to the active coal face.

Cash costs of production in Shanxi are still low compared to current prices. The pre-tax cost for mining, washing and loading coking coal is between Rmb350-400/tonne for most mines in the province, with SOE mine costs generally higher than the smaller ones as the only existing small ones now are newer, more efficient ones. We expect structural mining issues will cause real mining costs to inflate at least 5% a year, based on advice from industry experts.

Figure 134

Shanxi coking coal total cost delivered to Shanghai, 2010

0 100 200 300 400 500 600 700 800

Mining cost

Overheads

Taxes and fees


Railway loading

Railway


Port handling

Other

Ship to Guangdong

Port unloading

(Rmb/t)

Figure 135

Shanxi high cost mine delivered to Shanghai, 2010

0 200 400 600 800 1,000

Mining cost

Overheads

Taxes and fees


Railway loading

Railway


Port handling

Other

Ship to Guangdong

Port unloading

Port unloading

(Rmb/t)


Shanxi costs are low compared to current prices

Safety issues have contributed to a 30% jump in mining costs

Current cost for Shanxi coal to costal steel mills is

around US$120/t

High cost mines mainly suffer higher mining cost

and logistics charges



In terms of total costs, logistics can easily add up to more than Rmb250/tonne from Shanxi to a coastal steel mill, (see logistics section in main report). Royalties add another Rmb12/tonne currently, but under the likely resource tax reforms could well exceed Rmb35/tonne. There are many other taxes payable for mines in Shanxi, including environmental fees, safety fund and mineral resource compensation fund contributions among others. After adding in other non-mining costs such as sales and management of Rmb60-70/tonne the total cost base for an average Shanxi coking-coal mine is easily above Rmb750/tonne or US$115/tonne at current exchange rates. The highest cost mines with washing yields below 60%, which by some industry estimates account for 20% of production, have a cost of over Rmb900/tonne delivered to a coastal steel mill, or US$135/tonne.

Infrastructure - Barrier to growth China’s rail network currently has capacity to carry less than half the country’s coal.

Figure 136

Railway transportation of coal in China

(mt) 2003 2004 2005 2006 2007 2008 2009 1H10

Coal transported by railway 886 992 1,071 1,120 1,121 1,345 1,326 757

Total coal production 1,608 1,956 2,113 2,325 2,523 2,716 3,050 1,577

Share of railway transportation (%) 55 51 51 48 44 50 44 48


Shanxi is one of the better serviced provinces in terms of rail access, and higher value coking coal has traditionally taken preference over thermal-coal shipments.

Figure 137

Figure 138

Shanxi coal transportation

Inner Mongolia coal transportation


others39%


railway61%

Inner Mongolia coal transported by

others55%

Inner Mongolia coal

railway transportation

45%


Despite the considerable investment in expanding China’s rail network, the pace of growth in coal production has meant that infrastructure bottlenecks continue to cause problems in moving coal from production bases in the north to consumption centres in the east and south.

China’s rail infrastructure investment plans are discussed in more detail in the thermal-coal section of the report, but briefly it is the northern corridor which is most congested, and thus the focus of most investment in the rail network and the main area which will see capacity expansion. One key area is the expansion of the Shanxi to Shandong railway, which will allow producers there to bypass some of the busier Bohai basin ports and take coal out from Rizhao, near Qingdao.

Highest cost mines above US$135/tonne

Rail network will expand

Inflation and renminbi will drive rising costs

Resource tax could add cost pressure

Coking coal generally takes preference over thermal

Shanxi is relatively well serviced by rail

Coal production continues to outpace infrastructure

development



The cost for railing on the main Datong-Qinhuangdao line is Rmb0.12 per tonne per kilometre. Shanxi contacts suggested the cost of railing from Shanxi to Qinhuangdao totalled Rmb80-90/tonne for 600km, plus Rmb20-30/tonne port fees. Smaller miners have to pay an additional Rmb40-50/tonne to get access to the rail.

Shanxi is estimated to have no more than 600mtpa capacity to export coal by rail at present, with the rest going by truck into other provinces. Trucking costs have risen in recent years given the crackdown on overloading since 2007 which was destroying the road network. Trucking is economically viable for moving coal shorter distances, say under 300km, but costs vary a lot by province depending on the number of toll roads and local police enforcement of vehicle loading regulations. Inner Mongolia tends to have the cheapest trucking fees of Rmb0.25-0.40/tonne per kilometre, while in Shanxi trucking costs are as high as Rmb0.45-0.50/tonne per kilometre.

In many cases the transport cost for mines from Shanxi to a coastal steel mill is in excess of Rmb300/tonne.

The Ministry of Railway (MoR) expects railway capacity for coal to be raised to over 1.2 billion tonnes by 2013. It is expected that railway bottlenecks will be greatly reduced from 2014 as many new lines come into operation.

Taxes and trade - Swinging the balance Taxes represent a significant and rising cost for coal mines. As the government has clearly moved to restrict private coal mine production and improve safety standards in recent years, this has encouraged local authorities to levy an increasing number of taxes and fees on the mines.

A resource tax on coal has been speculated about for many years, but most industry players now expect this to be introduced next year, in the first year of the 12th Five-Year Plan. Resource taxes for primary coking coal are currently Rmb8/tonne, while the tax for other coals varies by province, but is generally between Rmb2.5-3.6/tonne.

The resource tax is widely speculated to be moving to between 3-5% of sales price. The net impact of this move would be to raise costs around Rmb20-25/tonne for coking-coal mines.

Other charges which mines incur include environmental taxes/sustainable development fund contributions, which in Shanxi is Rmb13/tonne but is likely lower elsewhere. The mineral resources compensation fund is applied nationally at 1% of sales revenue, while the safety fund is charged at Rmb2-10/tonne. The safety fund money is not paid to the government however, but kept by the mine to reinvest in safety equipment. Further additional taxes which are levied by some cities/provinces include relocation compensation expenses, price adjustment funds, city/infrastructure construction taxes and education supplementary taxes. All in all these additional taxes can easily exceed Rmb50/tonne for mines located in a built up or environmentally sensitive area.

In terms of trade taxes, China has gradually increased these over the years to dissuade exports. Prior to 2004, coke, coking coal and thermal coal all received generous tax rebates. After gradually reducing, eliminating, and then introducing export taxes, since 2008 coking and thermal coal have been subject to a 10% export tax, while coke is subject to a 40% export tax.

Rail costs vary according to additional fees

Taxes have increased a lot

Trucking costs are high, but viable over short

distances

Resource tax likely to be introduced

Expected to be 4% of sales price, net impact Rmb20-

25/tonne cost rise

Additional taxes are payable

Export taxes have risen to dissuade exports



Figure 139


Coke January 2001 15% export rebate January 2004 5% export rebate May 2004 Export rebate removed November 2006 5% export tax June 2007 15% export tax January 2008 25% export tax August 2008 40% export tax Coking coal Pre 2004 13% export rebate January 2004 5% export rebate May 2004 Export rebate removed November 2006 5% export tax August 2008 10% export tax Source: Ministry of Commerce, media reports, CLSA Asia-Pacific Markets

Figure 140

Chinese export quota changes

(mt) Coal exportquota

Actual coalexports

Coke export quota

Actual coke exports

2003 100 94 12 2004 80 87 13 162005 80 72 14 132006 80 63 14 142007 70 53 12 152008 47.7 45 12 122009 51 22 12 12010 1st batch 26 1Q-3Q 15 1st batch 4 1Q-3Q 2Source: Ministry of Commerce, CLSA Asia-Pacific Markets

Not only are these taxes a significant barrier to export volumes, but the trend of rising taxes over time clearly illustrates the Chinese governments rising desire to not be a serious exporter of low value, highly polluting products. Should exports of coke or coals become attractive in the future, we would expect to see further tax hikes to make it unattractive again. Consequently, we have very little in the way of exports of any coal products from China in our forecasts.

In 2010 Chinese coking-coal production has finally managed to surpass the pre consolidation peak of 2007. After struggling for the past two years, we are forecasting China’s coking-coal production growth recovering to a 5.5% Cagr over the next five years.

Figure 141

Chinese coking-coal supply - Base case

(mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLCrude steel prod 489 503 568 630 665 716 772 835 897Pig iron prod 477 469 544 609 641 686 746 807 863CC consumption 334 328 381 426 448 480 522 565 604Domestic CC 350 339 347 382 387 401 434 469 498Imported CC 6 7 35 45 62 80 89 97 107Exported CC¹ 22 18 1 1 1 1 1 1 1Import share (%) 2 2 9 11 14 17 17 17 18¹ Exports include coke. Source: NBS, CLSA Asia Pacific Markets

Import penetration will rise from 11% to 18%

by 2015

The government is increasingly against export

of low-value products

Coking coal production finally passed 2007 levels

in 2010

Exports used to be encouraged, but are now

discouraged

Quotas have been a good way of limiting exports



Indian coking coal - Domestic production concentrated in one area India has two major problems in terms of its domestic coking-coal supply. First, its coking coal is generally of lower grade, with higher sulphur and higher ash than average Australian coking coals. Second, over 95% of India’s coking-coal production comes from one province, Jharkhand, which while only a few hundred kilometres from the coast, is one of the main areas for Naxalite activity, which often provides a threat to the logistics and mines.

Figure 142

State-wise production of coking and non-coking coal

Coking (mt) FY06 FY07 FY08 FY09 FY10 % of totalChattisgarh 0.2 0.2 0.2 0.1 0.2 0.3Jharkhand 30.3 31.1 33.6 33.9 43.5 98.3Madhya Pradesh 0.9 0.8 0.7 0.7 0.5 1.2West Bengal 0.1 0.1 0.1 0.1 0.1 0.1Total 31.5 32.1 34.5 34.8 44.3 100.0Source: CLSA Asia-Pacific Markets

An additional problem from Jharkhand in expanding its coking-coal production is that there is so much local competition for infrastructure access. Together with the surrounding provinces that region accounts for over 60% of India’s thermal-coal output, and around half of its iron ore production too. This means demand for infrastructure expansions is very high and coal cannot be guaranteed priority.

A significant proportion of coal is consequently moved by truck. This remains very cheap in India, though very slow given the lack of major highways. The cost of trucking coal from Jharkhand even to steel mills near the west coast would be no more than Rs1,500/tonne (US$35/tonne), which combined with cheap mining costs means Indian coking coal is very cost competitive with imports on a delivered basis even after accounting for VIU adjustments.

The reason we look for Indian coking-coal imports to rise strongly in coming years is more to do with the technical limitations of Indian coal than their costs. As discussed in the demand section, most of India’s existing steel capacity is old and inefficient, and thus India has the worlds highest coke rates. A number of existing steel plants are being upgraded however, which combined with demand from new steel mills which are following the global trend in favour of larger furnaces, will raise the demand for structurally stronger HCC rather than the lower quality coking coal which India has itself.

Figure 143

Indian HCC imports

(mt) 08 09 10 11CL 12CL 13CL 14CL 15CLHCC consumption 37 40 46 52 57 66 75 78HCC domestic output 15 16 15 17 17 18 18 19HCC imports 22 24 31 34 40 48 57 59Source: Trade data, CLSA Asia-Pacific Markets

India lacks quality domestic coking-coal reserves

Trucking is not expensive

Coking coal production is concentrated in one state

Coking coal imports will account for 75% of HCC

consumption in 2015

Jharkhand is badly located for infrastructure

Appendices Coal outlook


Appendix 1: Data tables Chinese coal demand supply balance

(mt) 09CL 10CL 11CL 12CL 13CL 14CL 15CLProduction Key SOE 1,518 1,738 1,895 2,065 2,231 2,364 2,483Local SOE 366 391 391 391 391 391 391 TVEs 1,166 1,189 1,178 1,166 1,154 1,120 1,086Total 3,050 3,319 3,463 3,622 3,776 3,785 3,960Incremental supply 334 269 145 159 154 99 85YoY (%) Key SOE 10.3 14.5 9.0 9.0 8.0 6.0 5.0 Local SOE 6.0 7.0 0.0 0.0 0.0 0.0 0.0 TVEs 17.3 2.0 (1.0) (1.0) (1.0) (3.0) (3.0)Total 12.3 8.8 4.4 4.6 4.2 2.6 2.2Consumption Power generation 1,450 1,616 1,702 1,796 1,891 1,943 1,998 Heating 150 154 157 160 164 167 170 Coke making 476 533 560 600 653 705 755 Industrial end use 590 649 675 702 723 738 745 Non-industrial end use 134 137 139 142 145 148 151Gas making 15 17 18 19 20 21 21 Lost in washing 338 358 387 416 437 472 475Total 3,154 3,463 3,639 3,836 4,033 4,193 4,316Thermal trade Imports 92 119 130 150 180 230 255 Exports 22 19 10 5 5 5 5 Net exports (70) (101) (120) (145) (175) (225) (250)Coking trade Imports 35 45 57 70 83 94 107 Exports 1 1 1 1 1 1 1 Net exports (34) (44) (56) (69) (82) (93) (106)Net trade Imports 127 164 187 220 263 324 362 Exports 23 20 11 6 6 6 6 Net exports (104) (145) (176) (214) (257) (318) (356)Source: CCTD, NBS, CLSA Asia-Pacific Markets

Global thermal-coal seaborne import market (mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLSeaborne total 693 706 736 816 861 923 983 1,069 1,123China 45 34 92 119 130 150 180 230 255Japan 121 126 110 121 124 122 123 123 122Korea 67 78 84 93 93 95 97 99 101Taiwan 58 58 54 55 56 56 57 58 58India 33 37 47 59 80 120 145 175 200Other Asia 51 55 49 55 57 59 62 64 67EU27 187 185 179 184 186 184 182 180 178Other Europe 34 38 34 35 35 35 35 35 35Middle East & Africa 26 26 26 26 26 26 26 26 26North America 50 49 39 44 48 49 50 51 52South America 22 22 24 25 26 26 27 28 29

Global thermal-coal seaborne export market (mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLSeaborne total 684 716 730 782 845 910 977 1,075 1,161Indonesia 193 198 231 260 286 304 318 334 350Australia 111 121 134 137 140 180 240 330 410China 51 43 22 19 10 5 5 5 5Other Asia 16 21 24 26 28 30 32 34 36South Africa 68 68 67 66 69 70 73 77 78Russia 85 86 91 93 98 95 95 95 95US 24 35 19 21 28 26 24 22 22Colombia 65 69 63 68 76 82 85 88 90Other 71 75 78 93 110 118 105 90 75

Source: Australian Bureau of Agricultural and Resource Economics (ABARE), Trade data, McCloskey, CLSA Asia Pacific Markets



Global coking-coal seaborne import market (mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLSeaborne total 229 233 217 272 299 325 348 370 387China 6 7 35 45 62 80 89 97 107Japan 65 65 52 63 61 58 59 59 58Korea 21 22 19 22 26 28 29 30 31Taiwan 8 8 6 8 8 8 8 9 9India 24 28 29 35 38 42 49 59 61Other Asia 1 2 2 2 2 2 2 2 2EU27 67 67 48 63 64 65 68 70 70Other Europe 7 8 5 7 6 7 8 8 9Middle East & Africa 5 5 3 4 5 5 5 5 6North America 8 7 5 7 7 7 8 8 8South America 17 16 13 17 19 22 23 24 26

Global coking-coal seaborne export market (mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLSeaborne total 220 231 226 271 309 338 362 382 395Australia 139 139 139 154 171 179 181 185 187Mongolia 3 4 6 13 19 25 33 41 43China 3 2 1 1 1 1 1 1 1Other Asia 2 2 2 3 4 7 8 10 12Canada 26 27 24 27 32 36 39 40 40US (ex Canada) 26 35 32 48 55 59 62 62 62Mozambique 0 0 0 0 0 3 5 10 16CIS 11 13 13 15 17 19 23 24 25Other 11 9 8 10 11 10 10 10 10Apparent deficit 9 2 (9) 1 (10) (13) (14) (12) (8)

Global hard coking-coal seaborne import market (mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLSeaborne total 153 137 166 186 216 238 257 279 288China 5 5 26 35 52 66 73 79 86Japan 36 37 31 34 35 33 33 33 33Korea 12 12 12 13 15 17 17 18 19Taiwan 5 5 4 5 5 5 5 5 5India 19 22 24 28 34 40 48 57 59Other Asia 1 1 1 1 1 1 1 1 1EU27 49 36 45 45 48 48 50 55 52Other Europe 6 4 5 5 4 4 4 5 5Middle East & Africa 4 2 3 4 4 4 4 5 5North America 6 4 6 6 6 6 6 7 7South America 11 10 11 11 13 15 15 16 17

Global hard coking-coal seaborne export market (mt) 2007 2008 2009 10CL 11CL 12CL 13CL 14CL 15CLSeaborne total 144 155 148 185 211 234 248 263 273Australia 76 77 75 86 95 100 100 103 103Mongolia 2 2 3 8 11 14 18 22 23China 1 1 1 0 0 0 0 0 0Other Asia 3 3 3 4 5 8 9 11 13Canada 23 24 22 24 28 32 35 36 36US (ex Canada) 26 35 32 48 55 61 62 62 62Mozambique 0 0 0 0 0 3 5 10 16CIS 6 7 7 8 9 10 12 12 13Other 8 6 6 7 8 7 7 7 7Apparent deficit 8 (18) 18 1 5 4 9 16 15Source: Australian Bureau of Agricultural and Resource Economics (ABARE), Trade data, McCloskey, Industry sources, CLSA Asia Pacific Markets

North America and Russia contribute some growth



Appendix 2: Technical terms In terms of coal geology, there are four types of coal:

Anthracite. Least common of the coals, at less than 1% of world’s coal reserves. It contains 86-97% carbon with a slightly lower heating value than that of bituminous coal.

Bituminous. The world’s most commonly found coal (52% of world’s reserves), containing 45-86% carbon content. This includes all metallurgical coal grades.

Sub-bituminous. Sub-bituminous coal generates less heat per tonne compared to bituminous coal, but also has lower sulfur content and only 35-45% carbon content.

Lignite. This is the lowest grade of coal. It is crumbly, has high moisture content, generates the least heat content per tonne of all the coal types, and has only 25-35% carbon.

Coal types

Sales

High Moisture content of coalHigh Moisture content of coal Carbon/Energy content of coal HighCarbon/Energy content of coal High

% of world reserves% of world reserves UsesUses

SalesSalesPower generation

Cement manufactureIndustrial uses

Power generationCement manufacture

Industrial uses


Industrial uses


Industrial uses

Manufacture of iron & steel


Domestic/industrial including

smokeless fuel


smokeless fuel

Largely power generation


ThermalSteam coalThermal

Steam coalMetallurgical

Coking coalMetallurgical

Coking coal

Bituminous52%

Bituminous52%

Anthracite1%

Anthracite1%

Lignite17%

Lignite17%

Sub-bituminous

30%

Sub-bituminous

30%

Hard coal53%

Hard coal53%

Low rank coals47%

Low rank coals47%

SalesSales

High Moisture content of coalHigh Moisture content of coal Carbon/Energy content of coal HighCarbon/Energy content of coal HighHigh Moisture content of coalHigh Moisture content of coal Carbon/Energy content of coal HighCarbon/Energy content of coal High

% of world reserves% of world reserves UsesUses% of world reserves% of world reserves UsesUses

SalesSalesPower generation

Cement manufactureIndustrial uses


Industrial uses


Industrial uses


Industrial uses




smokeless fuel


smokeless fuel


Largely power generationSalesSales


Industrial uses


Industrial uses


Industrial uses


Industrial uses




smokeless fuel


smokeless fuel



ThermalSteam coalThermal



Coking coalThermal

Steam coalThermal



Coking coal

Bituminous52%

Bituminous52%

Anthracite1%

Anthracite1%

Lignite17%

Lignite17%

Sub-bituminous

30%

Sub-bituminous

30%

Bituminous52%

Bituminous52%

Anthracite1%

Anthracite1%

Lignite17%

Lignite17%

Sub-bituminous

30%

Sub-bituminous

30%

Hard coal53%

Hard coal53%

Low rank coals47%

Low rank coals47%

Hard coal53%

Hard coal53%

Low rank coals47%

Low rank coals47%

Source: World Coal Institute

Two main types of coal are used to make coke for steelmaking:

Hard coking coal (HCC) This type of coal is used to make coke, by heating in the absence of oxygen. HCC is structurally very strong and is layered in the blast furnace between iron ore to provide the energy to melt the iron and also an escape valve for gasses in the furnace. The volume of HCC required in a furnace depends on the size of the furnace, with more HCC required in larger furnaces as the weight of the burden is relatively higher.

Semi-soft coking coal This type of coal is similar to HCC but does not have the same physical strength, and is thus unable to hold up the burden in a blast furnace. It can be blended with HCC however, and can be used in a larger proportion in smaller furnaces where the structural properties are not so key. SSCC is used in the coke blend but results in a weaker coke and more impurities.



Coking coal is valued according to the following properties:

Coke Strength (CSR) This indicates the physical strength of the resulting coke. Coke is layered with iron ore in the blast furnace and has to be strong enough to support the iron ore. The larger the furnace, the greater the weight the coke has to support.

Ash Ash is the unburnt, inorganic residue left behind after coal is completely incinerated. The more ash, the lower the coke yield and the more slag (waste) is produced from the furnace, meaning more coke is consumed per tonne of pig iron.

Plasticity This refers to the melting and bonding behaviour of the coal.

Volatile Matter Indicates the amount of coal that will be gasified and given off during the coking process, impacting the coke yield.

Pulverised coal injection (PCI) This coal is crushed into a powder to be injected into the bottom of a blast furnace to provide energy to melt the iron ore into iron. However, as PCI doesn’t provide any structural benefits, only energy, there is a technical limit to how much can be used. The most advanced plants, such as Ijmuiden in Holland, use round 220-230kg PCI to produce one tonne of pig iron, and a similar amount of HCC. From this level it would be impossible to reduce HCC usage any further else the burden would collapse on itself. The global average PCI consumption is around 150-170kg/t.

Thermal coal This is any other coal without coking properties. Coal is mostly used for thermal power generation, and by the cement and other industries which require energy. Thermal coal is valued based on its energy content (Kcal/kg), ash content and sulphur content.

Others There are numerous other grades of coal, which mostly have a lower calorific (Kcal) value than thermal coal. This market sector is relatively small however, and given the problem with data classifications in trade and production data from most countries, it is impossible to separate these smaller market segments with any accuracy. Consequently, we just include all non-coking coals in thermal coal.

Washing and yield losses Most coal is washed at the mine site, which removes impurities and thus raises the value of the product to be transported. However, in China many mines lack washing facilities, and washing may be done in larger facilities which gather tonnes from many smaller producers. Consequently most

Classification of coking coal

Source: BMA



international statistics on coal production and trade are reporting washed, ie consumable, grades, but Chinese production data refers to raw, unwashed (or Run of Mine) coal. Mongolian coal is also mostly unwashed due to the lack of water in the country which is the main input for a washing plant.

Wash yields vary, but in some instances can lose up to 40% of ROM coal. This means the Chinese production data is substantially greater than the calculated consumption data. Inner Mongolia is a particular problem, as a significant volume of its coal production is low grade, unwashed lignite, which has a substantially lower calorific (energy) value than bituminous coal from other provinces such as Shanxi, and thus we have to make a significant upgrade to their relative production cost to reflect this value in use (VIU).

The blast furnace process

Coking-coal demand in the steel-making process

Source: Steel Technology Primer, Prudential Securities; BMA/BHP Billiton

Steel production process outline

Coking coal feeds into the blast furnace with iron ore



Appendix 3: Long-run Chinese steel The debate surrounding China’s potential steel consumption tends to focus on whether China can achieve per capita rates similar to other East Asian economies, or whether the fact that 60% of China’s population lives in landlocked provinces and hence should be immune from the influence of export industries will limit consumption to a similar level to the US or Europe. We firmly believe China can achieve a per capita rate of consumption greater than the US and Europe for a number of reasons:

Increasing urbanisation - Urbanisation may increase rather than slow over the next few years, as a way to achieve the government’s aims of social harmony. Concern over the widening wealth gap can only be alleviated by raising the wealth of rural people, and one of the key ways to achieve this is to encourage more people to move to the cities and for the remaining people to increase productivity on the farms. The government has already eliminated all agricultural taxes, which has helped to raise rural net incomes over the past decade at a similar pace to urban dwellers. However, given the low base, rural incomes need to grow much faster to begin to close the gap and this will require significant investment in productivity improvements.

China’s urbanisation rate

0

10

20

30

40

50

60

1990 1994 1998 2002 2006 2010 2014 2018

(%)

Source: Global Insight, CLSA Asia-Pacific Markets

Population density - Given ongoing urbanisation trends and China’s determination to prevent urban sprawl to maintain much needed agricultural land, China’s cities will have to grow upward rather than outward. With most of the population ultimately living in high rise apartments, this will also require better public transport infrastructure which is also steel intensive.

Steel-exporting sectors - While China’s economy will gradually rebalance from export driven to domestic driven demand, China will continue to be a major exporter of steel intensive goods such as ships, appliances and eventually cars, as with Korea, Taiwan and Japan. However, only 40% of China’s population lives in coastal provinces where these industries are prevalent, so exports on a per capita basis should be somewhat lower than in other East Asian countries.

Urbanisation will continue for many years

Trends towards taller cities will continue

Exports will continue to form a large part of the

economy

There are many reasons why China’s steel

consumption will grow



China’s steel containing export sectors, January to May 2010 YTD

0

10

20

30

40

50

60

70

80

90

100

Machinery Appliances Automotive Shipbuilding Containers

Export Domestic(%)


Economic development - China will continue to have high investment rates as infrastructure and apartments continue to be built. With 75% of the population still living in housing given to them by the government near 20 years ago, there is still a significant volume of construction activity to come. With the build quality of some of the recent buildings, it can also be argued there will be shorter replacement cycles in China versus Japan and Korea, though this will add to the scrap pool, which will be the ultimate downfall of iron ore prices in the 2020s.

While we believe China’s structural urbanisation trends and population density will result in an average 700kg/cap eventually, it won’t occur until China surpasses an upper-middle income level, ie, US$10,000 GDP per capita. With reference to other economies development, Japan only reached 600kg/cap in 1987 when GDP/cap was US$14,400, and peaked in 1990 at 752kg/cap when GDP was US$18,800. Taiwan only exceeded 600kg/cap when GDP was US$9,800/cap, while Korean GDP was US$10,200/cap before 600kg/cap was reached.

Global per-capita steel consumption

0

200

400

600

800

1,000

1,200

1,400

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000

China IndiaJapan KoreaTaiwan GermanyItaly China forecast

(kg/cap)

Source: Worldsteel.org, IMF, CLSA Asia-Pacific Markets

China’s steel intensity looks too high for its level of economic development

FAI rates will remain high for many years



The key to China reaching a 700kg/cap rate is economic development in the centre and west. Three coastal cities, Shanghai, Beijing and Tianjin already have a steel consumption rate of around 1,000kg/cap, similar to Korea and Taiwan, but their GDP/cap is also much higher than average at over US$10,000 per cap for Beijing and Shanghai. They also benefit from heavily export dependent industries and the presence of heavy steel consuming shipyards and car factories, similar to Korea and Taiwan. Obviously the land locked provinces will not be able to replicate these rates of steel consumption as they will struggle to develop any export related industries. Nonetheless, they should still be able to achieve consumption rates of around 500kg/cap just based on urbanisation, infrastructure requirements and general industrialisation.

Key areas are provinces, such as Hubei and Hunan, with populations of around 60 million each, a GDP rate of little more than US$3,000/cap and an urbanisation rate in the low 40%’s. As these provinces with larger populations reach the acceleration points in the development s-curves they will spur China’s growth to its potential 700kg rate.

China’s GDP per province and population

Population 70m~90m

Population > 90m

Population 40m~70m

Population 20m~40m

HeilongjiangGDP 121

JilinGDP 105Inner Mongolia

GDP 142

SichuanGDP 207

QinghaiGDP 16

TibetGDP 6

XinjiangGDP 63

GansuGDP 50

Population < 20m

Shanxi

GDP 108

Hebei

GDP 249

ShaanxiGDP 120

NingxiaGDP 20

YunnanGDP 90

HubeiGDP 188

JiangxiGDP 111Hunan

GDP 189GuizhouGDP 57

GuangxiGDP 113

ShandongGDP 495

JiangsuGDP 499

ZhejiangGDP 334

HainanGDP 24

FujianGDP 175

LiaoningGDP 221

HenanGDP 284

GuangdongGDP 572

AnhuiGDP 147

TianjinGDP 110

BeijingGDP 174

ShanghaiGDP 218

ChongqingGDP 96

GDP (2009) Unit: US$bn

Population 70m~90m

Population > 90m

Population 40m~70m

Population 20m~40m

HeilongjiangGDP 121

JilinGDP 105Inner Mongolia

GDP 142

SichuanGDP 207

QinghaiGDP 16

TibetGDP 6

XinjiangGDP 63

GansuGDP 50

Population < 20m

Shanxi

GDP 108

Hebei

GDP 249

ShaanxiGDP 120

NingxiaGDP 20

YunnanGDP 90

HubeiGDP 188

JiangxiGDP 111Hunan

GDP 189GuizhouGDP 57

GuangxiGDP 113

ShandongGDP 495

JiangsuGDP 499

ZhejiangGDP 334

HainanGDP 24

FujianGDP 175

LiaoningGDP 221

HenanGDP 284

GuangdongGDP 572

AnhuiGDP 147

TianjinGDP 110

BeijingGDP 174

ShanghaiGDP 218

ChongqingGDP 96

GDP (2009) Unit: US$bn


Coastal provinces already nearing Korean levels of

steel intensity

Inland provinces, with 60% of the population, are the key to sustained growth



With this solid foundation for consumption growth, we forecast China’s crude steel output to grow at a 7.3% rate over the next five years, and a 5.5% Cagr over the next ten years. The growth rate in coking-coal consumption will be slightly lower, but still above 5%, as scrap recovery in China will rise later this decade.

Scrap will displace coking-coal demand in the long run As China’s steel demand only began to surge in the early 2000s, the country’s current scrap pool is rather small compared with the size of its steel industry, and Electric Arc Furnace (EAF) steel production has seen little growth, remaining at 40-50 million tonnes for the past 10 years.

The pool of scrap steel in an economy generally lags steel consumption by 10-20 years. While steel from consumer-related usage (autos, appliances etc) may be scrapped in five to 10 years, most steel consumption tends to be in construction projects that have a useful life of up to 50 years. On average, most economies tend to see their scrap pool grow significantly only 20 years after their steel consumption accelerated. Korea’s obsolete scrap generation has been around 10-12 million tonnes over the past five years, which represents 25-33% of steel production lagged 10 years, or 50-75% of production lagged 20 years. Japan’s obsolete scrap generation is a similar proportion at 25-33% lagged 10 years, but given its steel output peaked in 1980, it is also only 25-33% of steel output lagged 20 years.

Assuming a similar obsolete scrap generation ratio for production lagged 10 years in China, which would be an increase from the 15-20% rates seen recently, the country’s obsolete scrap generation could be 150-200mtpa by 2020, up from 25 million tonnes in 2009. Should India’s steel demand accelerate in the next decade, it is likely that China would become a significant exporter of steel scrap (there is now a 40% export tax on scrap to keep all available supply within China, but we would expect this to be eliminated once supply is more than sufficient to meet domestic demand at the end of this decade). Nonetheless, it is still quite feasible that EAF steel production could rise by more than 100 million tonnes over the next decade, thus reducing the market for seaborne coking coal by 70 million tonnes from where it might otherwise be.

China’s potential scrap production

0

200

400

600

800

1,000

1,200

1980 1984 1988 1992 1996 2000 2004 2008 12CL 16CL 20CL

Steel consumption Scrap generated(mt)


Scrap is a serious long-run threat to iron

ore in China

Scrap generation lags steel consumption by

up to 20 years

China could be generating 150mtpa of scrap from

2020, up sixfold

China’s scrap generation will take off later

this decade



Appendix 4: Indian thermal demand India - Rising power India will see a strong rise in thermal generating capacity in coming years, and this will translate into significant demand for imports as domestic supply will struggle to keep up with demand growth (see supply section). While India will also import a growing volume of coking coal, its relative impact will not be as significant as for the thermal market.

Coal consumption pattern of India

0

100

200

300

400

500

600

FY07 FY08 FY09 FY10²

Power¹ Steel Cement Others(mt)

¹ utilities; ² provisional. Source: CLSA Asia-Pacific Markets

Thermal-coal demand to surge Demand for thermal coal in India will grow very strongly over the next few years, as a recent spate of investment in thermal generation plants come into operation. Nearly 75% of Indian thermal-coal consumption is by power utilities, with the remainder mostly from heavy industrial plants.

India power consumption by sector

Power - Utility75%

Other7%Cement

6%

Power - Captive8%

Steel (non-coking)4%


Indian thermal power capacity to rise strongly

Thermal-coal demand will surge in line with

generation capacity



India’s power demand basket - End-user breakdown

Domestic27%

Commercial8%

Irrigation22%

Industry35%

Others8%


Breakup of India’s GDP

0

20

40

60

80

100

FY75

FY77

FY79

FY81

FY83

FY85

FY87

FY89

FY91

FY93

FY95

FY97

FY99

FY01

FY03

FY05

FY07

FY09

Agri Industry Services(%)

Source: Ministry of Finance, Government of India, CLSA Asia-Pacific Markets

Electricity-demand and real-GDP growth

0

2

4

6

8

10

12

FY94

FY95

FY96

FY97

FY98

FY99

FY00

FY01

FY02

FY03

FY04

FY05

FY06

FY07

FY08

FY09

Demand Real GDPAverage demand Average GDP

(%)


Share of services in GDP has increased

progressively . . .

. . . which is not as energy-intensive as

industry and agriculture

Thus, elasticity of power demand has declined

Share of industry and agriculture has fallen

in the GDP . . .

. . . but still constitutes more than 50% of

power consumption

Growth in power demand has lagged

behind that in GDP



We expect power demand to grow more or less at the same rate as GDP, as India has a substantially smaller share of industrial output to GDP than China. Industry is the largest part of the pie in overall power consumption in the country. However the higher (and growing) share of services in GDP (which is less energy-intensive than industry and agriculture) could lead to a continued drop in elasticity of power demand. On the positive side, increasing industrial activity, electrification of villages and rising power supply over the next couple of years should all create additional demand for power.

To support the country’s strong GDP growth, the power sector will need to continue its aggressive capacity expansion beyond the 13th Five-Year Plan. CEA’s 17th Electric Power Survey (EPS) forecasts energy demand to increase from 745TWh in FY08 to 969TWh in FY12 - a Cagr of 6.8%. Peak demand is likely to increase from 113GW to 153GW (7.9% Cagr) over the same period.

Peak-demand forecast

Energy-demand forecast

113

122

131

142

153

100 115 130 145 160

2007-08

2008-09

2009-10

2010-11

2011-12

(GW)

745

795

848

906

969

600 700 800 900 1,000

2007-08

2008-09

2009-10

2010-11

2011-12

(TWh)


India already suffers from a considerable power deficit, estimated around 11%. With a large proportion of the population with no/inadequate electricity supply, India needs to continue adding capacity aggressively for many years.

Energy deficit

0

2

4

6

8

10

12

14

FY93 FY97 FY01 FY05 FY09 FY13E FY17E

(%)


We believe power shortages in India are understated. In many cases, they are reported by states that do not have adequate means to measure demand and supply. These states are disincentivised politically to report high loss levels. Moreover, a study by the National Council for Applied Economic Research (NCAER) shows Indian consumers - especially in smaller towns and villages - will buy more consumer goods that use electricity if power supply were to improve. We believe the same is true for a number of industries. Many manufacturing units have shied away from expanding capacity due to a

Both energy and peak deficit were in

double digits in FY09

Power shortages are understated

A 6.8% Cagr in energy demand over FY08-12 and

7.9% in peak demand

We expect demand to grow at the

same rate as GDP



lack of regular power supply. As this changes, we should expect a virtuous upward spiral in demand when rising availability allows manufacturers to invest in factories to consume more power and thus inspire further power capacity expansion and so on.

To meet this strong demand, generating capacity is already seeing massive investment, spurred by reforms earlier in the decade. In 2003, India passed the Electricity Act, which ushered in a new era of reforms, leading to a massive increase in new investment especially from the private sector. Capacity addition over FY10-13 should exceed that in the past 10 years with US$50bn being invested in the sector. In total India is likely to add about 50GW of total power capacity over the next three years.

Capacity-addition targets

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

FY93

FY94

FY95

FY96

FY97

FY98

FY99

FY00

FY01

FY02

FY03

FY04

FY05

FY06

FY07

FY08

FY09

FY10F

FY11F

FY12F

11th plan10th plan9th plan8th plan

12,282MW 19,015MW 21,095MW ~50,000MW


India has not finalised the capacity targets in its 12th Five-Year Plan yet, but preliminary studies indicate 100GW. GDP growth over this period is likely to be 7-8%.

Coal based power generation capacity (86GW) is 53% of the total installed capacity (162GW) in the country and it contributes 66% of the generation (in kWh). We have identified 105 thermal generation plants currently in operation throughout India, and another 59 which we expect to come into production over the next three years.



Demand 426 451 542 603 657 711

Domestic supply 374 387 432 473 489 522


India’s thermal-coal capacity expansions have struggled to deliver in recent years and we believe they are unlikely to accelerate in line with demand (see supply section). Consequently, the ramp up in Indian thermal power generation will lead to a surge in import demand for thermal coal, heavily weighted towards the next two years.

Better performance in achieving targets under

11th plan than in the past

The 12th plan would most likely target addition of 100GW

We expect 50GW addition in the 11th plan





Dependence on imports to increase The Ministry of Power expects coal imports for the power sector to increase from 16 million tonnes in FY09 to 68 million tonnes in FY12. We expect the imports to exceed these estimates significantly in FY12. For FY11, 35 million tonnes of imports have been targeted for blending purposes for power projects. The imports of dedicated imported coal-based power projects alone would be over and above this.

Demand/supply balance for coal for power in FY11 and FY12¹

(mt) FY11 FY12

Demand

Coal requirement for existing capacity 426 451

Coal requirement for FY11 additions 25 91

Total demand 451 542

Supply

Coal India 335 355

SCCL 31 33

Captive mines 22 22

Total supply 388 410

Gap 63 132

Imports required to fill the gap 43 90

¹ Calculations are done for 85% PLF. Source: CLSA Asia-Pacific Markets

Actual and expected imported coal requirements (for power sector¹)

90

43

28

16

101010

5334

0

10

20

30

40

50

60

70

80

90

100

FY02 FY03 FY04 FY05 FY06 FY07 FY08 FY09 FY10E FY11CL FY12CL

Actual imports(mt) Requirement

¹This is only for utilities and does not include captive power projects. Source: Ministry of Power, CLSA Asia-Pacific Markets

We believe it is too simplistic to assume that all gaps in domestic coal production would be filled up by imports, for example; there are many project locations in the country where it would be uneconomical to transport the imported coal from the ports. Thus, the utilisation rates for the projects where imported coal is not an option would be going down.

Coal imports are likely to increase significantly over

the next three years



Coal requirement for capacities commissioned in FY10

Thermal power station Agency/ Utility

Capacity(MW)

Coal requirement

Imported Domestic

Torrangallu U-1 JSW Energy 300 0.9 0.9

Torrangallu U-2 JSW Energy 300 0.9 0.9

Lanco Amarkantak U-1 Lanco Amarkantak

300 1.5 1.5

Bakreswar U-5 WBPDC 210 1.1 1.1

Kahalgaon U-7 NTPC 500 2.5 2.5

Bhilai U-2 NTPC/SAIL (JV) 250 1.3 1.3

Mundra Adani U-1 Adani Power 330 1.3 1.3

Suratgarh Ext. U-6 RRVUNL 250 1.3 1.3

Kota U-7 RRVUNL 195 1.0 1.0

Budge-budge U3 CESC 250 1.3 1.3

Vijayawada Ext. U-l APGENCO 500 2.5 2.5

Chabra U-1 RRVUNL 250 1.3 1.3

Dadri U-5 NTPC 490 2.5 2.5

New Parli Ext. U-2 MAHAGENCO 250 1.3 1.3

Rosa U-l Reliance Power 300 1.5 1.5

Chandrapura (DVC) U-7 DVC 250 1.3 1.3

Paras Ext. U-2 MAHAGENCO 250 1.3 1.3

Lanco Amarkantak U-2 Lanco Amarkantak

300 1.5 1.5

Mundra Adani U-2 Adani Power 330 1.3 1.3

Grand total 5,805 27.4 4.5 22.9


With demand for imported coal clearly set to soar, Indian companies have been using a variety of strategies for securing imported coal:

Equity stakes in coal mines abroad. Tata Power has been the first mover in this field by taking up equity stakes in the Arutmin and KPC mines of Bumi Resources in Indonesia. The company has acquired a high quality coal asset with this move and is also assured of the off-take for its 4,000MW Mundra power project. Coal India is also considering the same strategy of taking equity stakes and in turn having an off-take agreement. The positives in this strategy are that the Indian company need not have operations in the foreign land and is assured of an off-take agreement. However, the risk is too much dependence on the foreign player and a possible lack of transparency.

Long-term coal purchase agreements. Some companies have entered into long-term contracts with the coal mining companies/coal traders to supply coal for the life of the projects. Lanco has entered into this kind of arrangement for its Nagarjuna project of 1,025MW. The coal prices in such contracts usually have a base coal price and a variable part which is linked to standard coal indices.

Back to back agreements with entities having mining licences. This is a strategy chosen by a number of Indian players, including Adani Power and JSW Energy. The mining licence in this case is held by a

Tata Power owns a 30% stake in KPC and Arutmin

mines in Indonesia

Change in mining laws is the biggest risk



foreign partner (company or an individual) who transfers his rights to a company owned by the Indian company which will do the mining as well as use the coal.

Risks common to all strategies are:

A change in mining laws in the foreign countries is a risk for all the above strategies.

The direction of coal prices could impact the second and the third strategy more than the first.

Ocean freight costs are also a key variable for importing large volumes of coal. Some companies have entered into long-term charters or purchased ships to mitigate this risk.

India has a number of geographical advantages to becoming a significant coal importer. Given the volume of iron ore and other materials imported in China from Brazil, there is a considerable surplus of empty ships making the return journey. Thus ship owners will charge very low rates for vessels to carry a coal cargo from Australia or Indonesia into India, en-route back to the Atlantic market. Also, India is positioned significantly closer to Indonesia and South Africa than Europe and North Asia, so will see much cheaper landed cost of coal. For energy this is not so important given energy is not traded across borders, but for steel this is a significant advantage for the Indian steel industry in turning increasingly toward coking-coal imports.

Other reasons why we are positive on India’s prospects to become a major thermal-coal importer are that India’s coal is mostly located in the north and northeast, and the logistics troubles of moving coal to the coast to ship around the coast is very problematic, especially when that area is also one of the major iron ore production bases. The presence of Naxalite rebels is also a major barrier to further infrastructure investment in the area. Additionally, India has an extensive coastline, so seaborne imports make considerable sense for power plants located in the south and west of India as imported coal does not need to travel too far inland. We believe these factors contribute upside to our thermal-coal import volume forecasts.



Appendix 5: Chinese power demand China’s thermal-coal imports have risen from 13 million tonnes in 2007 to 39 million tonnes in 2009, and an annualised 60 million tonnes over 1H10. On a net basis, China has switched from being an exporter of 32 million tonnes in 2007 to net imports of 20 million tonnes in 2009. Thermal coal accounts for approximately 30% of China’s coal imports.

China thermal-coal import and export

(40,000)

(30,000)

(20,000)

(10,000)

0

10,000

20,000

30,000

40,000

50,000

2007 2008 2009 2010 Jan-Sep

Thermal coal import Thermal coal export Net import('000 t)

Source: CCTD, CLSA Asia-Pacific Markets

Unlike coking-coal demand, which we expect to see solid growth in the years ahead, for thermal coal we expect demand to slow significantly, as the economy rebalances away from investment driven growth.

One of the key drivers of China’s rising energy intensity since 2002 has been the structural change in its economy. There was a spike in FAI as a proportion of GDP from 2003 onwards. Prior to that in 1990-02, the ratio of FAI rose by 12ppts or on an average 1ppt per annum. However, during 2002-09 this went up by 31ppts or 4.4ppts per annum, growing from Rmb4,350bn in 2002 to Rmb22,484bn in 2009 - a 26% Cagr.

China’s FAI as percentage of GDP

67

55535248

4441

34333334323233

3537

30

2624

36

0

10

20

30

40

50

60

70

80

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

(%)

1990-2002 = 12ppt increase

2002-09 = 31ppt increase


China’s FAI increase jumped from 1ppt per

annum to 4ppts

Higher FAI drove rising energy intensity



China FAI rose to Rmb22tn in 2009

0

5,000

10,000

15,000

20,000

25,000

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

(Rmbbn)

Deng's southern tour

China joins WTO


This led to unprecedented growth in high energy-consuming sectors like ferrous and nonferrous metals, cement and chemicals. These sectors’ share in industrial energy consumption rose from 47.8% in 2002 to 55.7% in 2007. China joined the WTO in 2001, and won the 2008 Olympics bid in the same year. Accession to the WTO had a big impact on exports, which in turn played a part in energy consumption growth.

Another way to look at the phenomenon of rising investments as a proportion of GDP is through gross capital formation (GCF). Our economist Eric Fishwick points out that this is a measure more comparable to other economies as the way land transactions are measured overstates the FAI figure.

During 1980-01, GCF as a percentage of GDP was up only 1.6ppt (despite a lot of volatility). From 2003 onwards there was a marked increase in the capital investment driven growth and GCF as a percentage of GDP rose by 11ppts to reach 47.5% in 2009.

There has been a high correlation between China’s energy consumption and China’s GCF growth However, it is also apparent that while a pick up in GCF was one of the causes of higher energy intensity the ratio of energy consumed to GCF also rose. This is because the share of higher energy-consuming sectors - ferrous and nonferrous metals, cement and chemicals rose very sharply during this period.

Gross capital formation as % of GDP Growth in energy use vs GCF growth

30

35

40

45

50

1980 1989 1998 2007

Increase over 1980-2001 = 1.6ppt

Increase over 2001-2009 = 11ppt

(%)

(10)

(5)

0

5

10

15

20

25

1981 1990 1999 2008

GCF growthGrowth in energy consumption

(%)

Source: CEIC, NBS, CLSA Asia-Pacific Markets

FAI has increased sixfold since China joined the WTO

Increase in GCF as percentage of GDP

accelerated from 2002

Growth in GCF and energy consumption have

high correlation

China’s share of high-energy consuming sectors

rose with share of GCF

Sharp growth in energy consuming sectors - metals,

cement and chemicals



Manufacturing sector drove growth in energy demand We have analysed China’s energy demand growth during the five-year period from 2002-07 and the preceding five years 1997-02. The overall energy consumption during the latter period grew by 176% (versus 117% in the previous five-year period). While in 1997-02 energy-consumption growth by the manufacturing sector was lower than overall energy growth; during 2002-07 it was significantly higher. The highest rate was in the ferrous and nonferrous metal sectors.

Growth in energy consumption in China across sectors

10394 88

137

108117

176

238243

187184194

0

50

100

150

200

250

300

Manufacturing RawChemicals

Non metallicminerals

Non ferrousmetals

Ferrousmetals

Total

1997-02 2002-07(%)


Power demand growth Analysis of power demand growth by segments reveals an even starker picture. Reliable data for power consumption was available for a longer time and hence we have compared power consumption trends during 2002-09 with those during 1995-02. Overall growth in power consumption in the later period was almost double. However, growth in power consumption in the manufacturing sector was almost three-fold and in nonferrous metals more than four-fold.

Growth in electricity consumption in China across sectors

55

32

47

94

46

64

125

212208

142

112

145

0

50

100

150

200

250

Manufacturing RawChemicals


Non ferrousmetals

Ferrousmetals

Total

1995-2002 2002-09(%)


Growth in power demand from manufacturing shot up Between 1985 and 2002 power demand growth in the manufacturing sector was lower than the overall power demand growth in most years. However, this changed from 2003 onwards with the manufacturing sector accounting for much higher growth.

Manufacturing sector was an important driver of

growth post 2002

Metals, cement and chemicals drove most of

the growth in energy use

Post 2002 power demand growth in manufacturing jumped nearly three-fold

Pre-2002 power demand growth from manufacturing

was less than total growth

High-energy consuming industries grew faster



Total vs manufacturing power demand Total vs ferrous metal power demand

0

5

10

15

20

1986 1993 2000 2007

Total power demand

Manufacturing

(%)

0

4

8

12

16

20

24

28

1986 1993 2000 2007

Total power demand

Ferrous Metals

(%)


This trend is even more evident in the growth of power demand for ferrous metals where the power demand growth was almost twice as high as the average power demand growth during some years.

Sharp increase in production of energy intensive goods The spike in energy and power consumption in these sectors was driven by an unprecedented production growth of steel, nonferrous metals, cement, chemicals, autos, power-generation equipment, and mining equipment.

Steel production in China Production of sulphuric acid in China

0

100

200

300

400

500

600

700

1980 1984 1988 1992 1996 2000 2004 2008

Cagr over 1980-2002 = 9.3%

Cagr over 2002-2009 = 20.2%

(m tonnes)

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

1980 1984 1988 1992 1996 2000 2004 2008

Cagr over 1980-2002 = 6.5%

Cagr over 2002-2009 = 10%

(mt)

Cement production in China Mining equipment production in China

0200400600800

1,0001,2001,4001,6001,800

1980 1984 1988 1992 1996 2000 2004 2008

Cagr over 1980-2002 = 10.6%

Cagr over 2002-2009 = 12.5%

(mt)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1980 1984 1988 1992 1996 2000 2004 2008

Cagr over 1980-2002 = 7.8%

Cagr over 2002-2009 = 22.1%(mt)

China’s motor vehicle production growth Key drivers of power-demand growth

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

1980 1984 1988 1992 1996 2000 2004 2008

Cagr over 1980-2002 = 13%

Cagr over 2002-2009 = 22.9%(mt)

6.36.1

4.25.9

8.5

13.4

6.17.4

02468

10121416

RawChemicals


Non ferrousmetals

Ferrousmetals

1994-2002

2002-2009

(%)

Source: CEIC, CLSA Asia-Pacific Markets Source: CLSA Asia-Pacific Markets

Power demand for ferrous metals jumped sharply

after 2002

A turning point was 2002 with growth in high

energy-intensive sectors

Post 2002 growth in manufacturing power

demand exceeded total

Ferrous metal power demand grew rapidly

from 2000-07

Steel production growth in China rose from 9% to

20% in 2002-09

Sulphuric-acid production growth rose by 3.5ppts

Rate of growth in cement production rose too

Growth in mining equipment production

trebled in China

Motor-vehicle production growth has nearly

doubled in recent years



We have looked at the key sectors contributing to incremental power demand during 1994-02 and 2002-09, in the first period total incremental power demand from raw chemicals, ferrous and nonferrous metals and nonmetallic mineral products was around 22.5%, in the later period these four sectors accounted for 35.5% of China’s incremental power demand growth.

China’s energy consumption versus the rest of the world China’s investment-led growth and consequent boom in energy consumption has meant that there is a big difference in the composition of its energy use and economic structure compared with the rest of the world - including developing countries like India.

China’s industrial use is huge with a 72% share of energy consumption last year, compared with less than half that figure for India, Russia, OECD Europe, the US and Japan.

Energy consumption in 2009

72 32 33 28 20 33

8

12

2430 44

27

21

56

42 4335 39

0

10

20

30

40

50

60

70

80

90

100

China India Russia OECD Europe US Japan

Industry Transport Residential, Commercial & AG(%)

Source: CEIC, Datastream, CLSA Asia-Pacific Markets

This is due to China’s unusually high dependence on industry, which accounted for 46% of China’s economy last year, compared with 28% for India and 24-33% for the US, EU, Japan and Russia. The high share to a large extent explains China’s high-energy consumption per unit of PPP GDP.

GDP by industry in 2009

46

28 2419

28 33

4355

7480

7162

5

1

12

17

10

0

10

20

30

40

50

60

70

80

90

100

China India EU US Japan Russia

(%) Industry Agriculture Services

Source: CEIC, Datastream, CLSA Asia-Pacific Markets

China’s energy use and economic structure

is unique

In 2009, 72% of China’s industrial energy use was

more than double most other countries

Compared to others China has a much higher share

of industry in GDP

Next closest country is Russia, 13ppts less

than China

Share of metals, cement and chemicals rose from

22.5% to 35.5%



While China’s energy consumption on a whole has surpassed expectations, the main surprise has come from sharper growth in coal consumption. Around half is used for power generation and the share of power generation in coal consumption has risen over time.

Electricity has been the fastest growing energy form, with growth accelerating since 2002. The sharp increase in FAI is only half of the story. In reality the sharp rise in electricity availability (and coal) has also contributed to the sharp higher FAI creating a virtuous cycle leading to more use.

Growth in the consumption of various forms of energy in China

0

100

200

300

400

500

600

700

800

900

1,000

1982 1986 1990 1994 1998 2002 2006

Energy Coal Oil Gas Electricity(%)


What led to more power and coal availability since 2002 has been reforms in both the sectors, which created incentives for players to add more mining and generation capacity (as outlined in the supply section of this report).

Future growth in coal consumption will be reduced The three challenges China faces are reducing the energy consumption per unit of economic output, changing the mix of that energy towards greener energy and reducing the environment pollution from energy being consumed. Achieving these objectives involves economic, legal, political and social reforms, but as they are achieved the pace of demand growth for coal will slow substantially.

Moving away from investment-led growth In 2007, Premier Wen Jiabao issued a dire warning that is worth repeating.

‘The biggest problem in China’s economy is still the imbalances in the structure - that economic development is not stable, balanced, harmonious and sustainable.

‘Investment growth is too high, credit growth is too fast, liquidity is excessive and trade and international payments are not balanced.

‘All these problems facing us need to be urgently addressed and will need our continued efforts to solve them.’

Electricity use has grown 10x since 1980s - higher than other energy forms

The key surprise was sharp growth in coal use -

mostly for electricity

Electricity is the fastest growing form of energy

use in China

Three challenges are energy intensity, energy

mix and pollution



Our economist Eric Fishwick and China strategist Andy Rothman agree that over the medium to long term China will reduce its reliance on investment for growth but both also believe it will not be easy and hence will happen only gradually. The relative importance of consumption versus investment as a growth driver will continue, though at a gradual pace. This also ties in with the World Bank view expressed in its report China through 2020 - A macroeconomic scenario.

In the report the authors argue that China’s investment growth is likely to decline from 2010 onwards, after the massive expansion in 2009 and in line with the objective to rebalance the pattern of growth, towards less investment and industry and more consumption and services.

Our economist Eric Fishwick also expects the growth in gross fixed capital formation (GFCF) to slow down from 21-23% levels in 2008 and 2009 to 18.4% in 2010, 13.4% in 2011 and 15.6% in 2012. He expects the GCF as a percentage of GDP to continue to rise until 2012 and fall after that.

This is good news for China as experience of other economies shows that the growth in energy and power consumption falls (quite sharply in some cases) once the gross capital formation as a percentage of GDP peaks.

Experience of other economies So what happens once gross capital formation as a percentage of GDP peaks out? We have analysed the experience of Japan, Korea and Mexico once GCF as a percentage of GDP peaked out for these countries. The vertical line in the chart below reflects the peak year (for China the vertical line represents 2009) and energy demand growth rates 10 years before and after for each country.

Energy consumption growth before and after GCF as a percentage of GDP peaked out

(10)

(5)

0

5

10

15

20

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

(YoY %) China Japan Korea Mexico

GFC Peak

Source: CEIC, World Bank, CLSA Asia-Pacific Markets

The results are pretty unanimous - the energy consumption growth rates in all these economies fell in the decade post-GCF peak from the decade pre-GCF peak. Even a five-year analysis pre- and post-peak gives similar results.

Investment growth likely to decline from 2010 onwards

CLSA expects GCF growth to fall in 2010 and 2011

China will reduce its reliance on investment

for growth

Energy consumption growth rates fall around

the time as GCF as a percentage of GDP peaks

GCF trend has been observed in a

number of economies

Energy consumption growth before and after GCF



Energy consumption growth 10 years before and after GFCF share peaked

(%) Energy consumption growth Electricity consumption growth Japan peak - 1990 10 years prior 2.2 3.810 years after that 1.8 2.6% change (15.4) (32.8)Korea peak - 1991 10 years prior 9.1 11.610-years after that 6.5 10.5% change (28.3) (9.4)Mexico peak - 1981 10 years prior 9.010 years after that 2.3% change (74.7)

Energy consumption growth five years before and after GFCF share peaked

(%) Energy consumption growth Electricity consumption growthJapan peak - 1990 10 years prior 3.6 4.510 years after that 2.3 2.9% change (35.4) (35.5)Korea peak - 1991 10 years prior 11.0 13.010 years after that 9.2 11.7% change (16.5) (9.7)Mexico peak - 1981 10 years prior 1.8 3.910 years after that (1.0) 2.2% change (154.6) (43.9)Source: CEIC, World Bank, CLSA Asia-Pacific Markets

Implications for China - A sharper decline in energy use As we have seen for some other major economies the energy consumption growth rates fell (in some cases pretty sharply) as GCF as a percentage of GDP peaked out. We expect a drop in China’s case. However, there are a few important differences. First, China’s economy is far more investment driven than Japan, Korea and Mexico when the investment as a percentage of GCF peaked out in those economies. China is likely to be close to 50% at the peak, compared to 40% for Korea, 33% for Japan and 27% for Mexico.

Secondly, China’s economy is far more coal driven than any of the other three economies. Consequently, it is more polluting and emits more CO2. Thirdly, the slowdown in energy consumption in those three economies occurred at a time when global warming was nowhere close to being as big a threat as today. All this makes us believe that the slowdown in energy consumption growth in the case of China is going to be much sharper than Japan and Korea and more similar to Mexico.

Production of energy intensive goods should fall As China’s economy moves from an industry- and investment-led economy to a services and consumption led economy, the production of metals and cement - building blocks for most of investment and industry - will also slowdown sharply. Growth rates for steel are likely to roughly halve over the next five years compared with the past five, while those for aluminium and cement are likely to come down by around one third of the past five years.

China will experience a similar slowdown once GCF

peaks as a % of GDP

Over the short term the trend may be exaggerated

China’s energy growth slowdown to be sharper

than Korea or Japan

May resemble the trend observed in Mexico

Consumption of metals and cement should slow



Growth for production of steel, aluminium, copper and cement in China

59.368.8

140.8

82.6

21.9

45.542.840.0

25.220.5

12.6

0

20

40

60

80

100

120

140

160

Steel Aluminium Copper Cement

2005-10 2010-15 2015-20(%)


While we do not have estimates for the chemicals industry we expect a similar trend in production growth too. The metals, cement and chemicals sectors combined, accounted for 53% of total energy consumption by industry in 2007 and 58% of the incremental-energy demand by industry over 2002-07. A slowdown in these sectors will have a substantial impact on the overall energy demand in the country.

Our three-year moving average growth rate estimates for metals and cement

(5)

0

5

10

15

20

25

30

2005 10CL 15CL 20CL 25CL 30CL

Steel

Aluminium

Copper

Cement

(%)


Energy efficiency - The magic bullet The second leg of China’s reduction in its energy diet will revolve around energy efficiency. Globally, energy efficiency will be the biggest contributor to GHG reduction. Most of the energy contained in energy resources is lost in the value-chain from extraction to end use.

Given China has already closed a lot of its most inefficient power capacity, and given the breakneck speed of power capacity additions in the past ten years, the room for further improvement is limited. Some 75% of China’s thermal current power capacity is less than 10 years old.

High-energy intensity industries should grow

slower over 2010-20

Cement and steel consumption set to decrease post 2010

Energy efficiency is key to GHG reduction

Metals, cement and chemicals use 53% of

industrial energy

Some 75% of China’s thermal capacity built over the last 10 years



Among all major countries this makes China’s current power fleet the most recent. That does not mean that China’s thermal power capacity is most efficient though. In a hurry to add capacity we understand China has compromised on the quality of equipment to some extent. For instance the heat rates of the supposedly more efficient 660MW supercritical power plants supplied by China are higher than the heat rates of 500MW subcritical power plants in India according to Central Electricity Authority in India.

Evidence China’s energy-conservation efforts are working A recent report by our China Reality Research (CRR ) team Energy Efficiency to help smooth price volatility gives concrete evidence of China government’s energy efficiency efforts starting to have effect on the ground level. Some interesting excerpts from the report are given below:

Under pressure from Beijing and their own desire to reduce costs, major coal end-users have cut consumption (per unit of production) by an average 12.6% since 2005. They plan to make further annual reductions of 3.3% in 2011-13. Cement and fertiliser makers see the biggest room for further cuts.

Coal efficiency improves in key industries. On average, the 39 big coal users we looked at have cut their per-unit product coal consumption by 12.6% since 2005. Fertiliser plants and IPPs have achieved an average reduction of 19% and 16.8%, while the cement and steel mills cut their per-unit product coal consumption by just 12%.

Further room for coal saving. These end-users see further room to cut coal intensity over the next few years by closing excess capacity. The cement makers see the biggest room to further cut coal use, while the power generators see the least. Compared with the power sector which has seen over 70GW of small coal-fired generators closed since 2005, China’s cement industry still has some 400 million tonnes of outdated capacity, or 20% of total existing capacity, that should be shut down in the future.

How much have you cut per-unit product coal consumption since 2005?

(12.6)(12.0)(12.0)

(16.8)

(19.0)

(30)

(25)

(20)

(15)

(10)

(5)

0

Fertilizerproducer

Power plant Cement plant Steel mill Overall¹(%)

¹ Weighted by % of the related sector to China's total coal consumption in 2009. Source: CRR

China has the most modern power fleet

CLSA Asia-Pacific Markets

Second-biggest cuts came from power plants

CRR shows that energy conservation efforts are

yielding results

Our CRR team talked to 39 big end-users of coal

in 20 cities



Cagr of coal saving by sector among the 39 end-users

(2.6)

(3.7)(4.2)

(2.6) (2.8)(3.3)

(8.0)

(3.2)

(6.7)

(2.3)

(9)

(8)

(7)

(6)

(5)

(4)

(3)

(2)

(1)

0

Fertilizerproducer

Power plant Cement plant Steel mill Overall¹

2005-year to date

2011-2013F

(Cagr %)

¹ Weighted by % of the related sector to China's total coal consumption in 2009. Source: CRR

Average coal consumption per unit output among the 39 end-users

1,725

89

614

379

130

752

1,439

312

114

658

1,343

303

105

643

1,253

96

628

293

1,169

284

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Fertilizer¹ Power plant Cement Steel²

(unit³) 2005 Current 2011F 2012F 2013F

¹ In terms of urea per tonne; ² Include both coking coal/thermal coal and electricity consumption. ³ g/kWh for power plant and kg/tonne for the rest. Source: CRR

China’s future energy consumption trends The structural changes in China’s economy (consumption and services driven growth), urbanisation and increased focus on energy efficiency will certainly lead to a substantial slowdown in China’s energy consumption. However, to quantify that slowdown is a bit tricky as China has frequently revised its past energy-consumption data and figures available from various government bodies at times do not match.

The various conversions from raw coal tonnes to standard coal tonnes and to mtoe to kWh also do not always stack up using standard conversion metrics, which should be taken into account. We have tried to make as much sense as we could of the diverse and often contradictory data available. First, we begin by analysing the government estimates on future energy consumption and then we present our conclusions.

Government targets on energy intensity In 2009 the Energy Research Institute came out with a detailed paper discussing China’s energy consumption targets for 2020-50 based on three scenarios - base case, low carbon and super low carbon.

Cement has the best scope of improvement for

energy efficiency

Improvement potential across industries

Difficult to quantify China’s energy

consumption slowdown

Take note of conversions into standard coal tonnes



In the base case China expects the energy consumption growth to slow to 3.4% from 2010 to 2020 and 1.4% from 2020 to 2030. In the low-carbon and super-low carbon scenarios energy consumption is even lower. In the super-low carbon scenario the growth in energy consumption between 2020-30 is negative. In these scenarios the mix of coal is much lower, while the mix of renewables, hydro power and nuclear power capacity is much higher.

Base scenario primary energy demand (mt of coal equivalent)

Year Coal Oil Natural gas

Hydro Nuclear Solar/Wind

Biomass Alcohol Biodiesel Total

2000 944 278 30 85 6 0 1 0 0 1,346

2005 1,536 435 60 131 20 1 2 2 1 2,189

10CL 2,424 628 109 217 28 7 16 10 1 3,438

20CL 2,991 1,096 271 294 90 20 30 22 3 4,817

30CL 2,932 1,708 460 358 181 54 44 33 8 5,526

40CL 3,001 1,710 532 380 380 84 71 36 9 6,202

50CL 2,925 1,836 668 397 595 103 86 39 9 6,657

% Cagr in energy demand

10-20CL 2.1 5.7 9.5 3.1 12.4 11.1 6.5 8.2 17.8 3.4

20-30CL (0.2) 4.5 5.4 2.0 7.2 10.4 3.9 4.1 9.8 1.4

30-40CL 0.2 0.0 1.5 0.6 7.7 4.5 4.9 0.9 0.7 1.2

40-50CL (0.3) 0.7 2.3 0.4 4.6 2.1 1.9 0.8 0.8 0.7

Low-carbon scenario primary energy demand (mt of coal equivalent)


Hydro Nuclear Wind Solar Biomass Alcohol Biodiesel Total

2000 944 278 30 85 6 - - 1 - - 1,346

2005 1,536 435 60 131 20 1 - 2 2 1 2,189

10CL 2,173 528 109 207 46 12 - 9 2 1 3,087

20CL 2,195 843 349 375 136 51 1 32 8 6 3,996

30CL 2,091 964 529 401 301 92 4 52 28 12 4,474

40CL 2,063 1,010 628 424 471 118 9 61 36 13 4,833

50CL 1,984 1,025 745 422 760 169 20 68 44 14 5,250


2000-10 3.5 2.0 6.2 4.7 8.7 28.2 16.2 0.0 0.0 3.5

10-20CL 0.1 4.8 12.3 6.1 11.4 15.6 13.5 14.9 19.6 2.6

20-30CL (0.5) 1.4 4.2 0.7 8.3 6.1 14.9 5.0 13.3 7.2 1.1

30-40CL (0.1) 0.5 1.7 0.6 4.6 2.5 8.4 1.6 2.5 0.8 0.8

40-50CL (0.4) 0.1 1.7 0.0 4.9 3.7 8.3 1.1 2.0 0.7 0.8

Super low-carbon scenario primary energy demand (mt of coal equivalent)


Hydro Nuclear Wind Solar Biomass Alcohol Biodiesel Total

2000 944 278 30 85 6 0 0 1 0 0 1,346

2005 1,536 448 60 131 20 1 0 3 1 0 2,203

10CL 2,083 532 107 180 40 18 0 8 2 1 2,971

20CL 2,144 838 330 354 145 66 1 31 8 6 3,921

30CL 1,903 943 491 395 301 156 5 49 20 12 4,275

40CL 1,814 993 604 429 497 214 16 59 22 13 4,660

50CL 1,715 1,032 710 420 761 239 37 63 23 14 5,014


10-20CL 0.3 4.6 11.9 7.0 13.7 13.9 14.5 14.9 19.6 2.8

20-30CL (1.2) 1.2 4.1 1.1 7.6 9.0 17.5 4.7 9.6 7.2 0.9

30-40CL (0.5) 0.5 2.1 0.8 5.1 3.2 12.3 1.9 1.0 0.8 0.9

40-50CL (0.6) 0.4 1.6 (0.2) 4.4 1.1 8.7 0.7 0.4 0.7 0.7

Source: ERI, NDRC, CLSA Asia-Pacific Markets

ERI estimates energy consumption growth to

slow to 1.4-3.4%

Energy demand in aggressive

low-carbon scenario

Energy demand in the base scenario

Energy demand in baseline low-carbon

scenario



Our estimates for energy consumption The structural changes in the economy, as well as increased focus on energy intensity will be able to achieve a sharp slowdown in China’s energy consumption growth. We expect China’s average annual energy-consumption growth rate to come down from around 8.9% over 2000-10 to 3.8% during 2010-20 and 1.6% during 2020-30.

Growth in China’s annual energy consumption

0

2

4

6

8

10

12

14

16

18

1981 1985 1989 1993 1997 2001 2005 2009 2013 2017 2021 2025 2029

Growth in energy consumption

Average for the decade

(%)


Our estimates are a bit higher than those of ERI’s base case but broadly in line. For 2020 our forecasts are around 2% higher and for 2030 they are 4% higher. However, our base-case estimates assume a higher share of renewable and nuclear power (discussed in detail in the next section) in China’s overall energy mix. We believe ERI estimates have underestimated the extent of pick up in wind power and nuclear power installations.

However, despite a higher share of renewables in our base case, our coal demand assumptions are not very different to ERI’s, given that the marginally higher overall energy consumption estimates absorbs most of our ‘additional’ renewable energy production.

Our estimates versus ERI’s

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2010 2020 2030

ERI base case

ERI low carbon

ERI super low carbon

Our estimates base case

(m tonnes)

Source: ERI, CLSA Asia-Pacific Markets

We expect energy consumption to slow to 3.8% over 2010-20 . . .

Our estimates assume a higher share of renewable

and nuclear power

Our coal demand assumptions similar

to ERI

We have modelled higher energy consumption

. . . and by 1.6% over 2020-30



Lower elasticity of energy consumption to GDP growth is a key driver The key driver for slower energy consumption is the lower energy elasticity of the Chinese economy, though lower GDP growth forecasts compared with the past also helps. We expect the elasticity of energy consumption growth to GDP growth to come down from 0.88 in the last decade to 0.5 during 2010-20 and further to 0.3 during 2020-30.

China’s energy elasticity is set to decline

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1981 1985 1989 1993 1997 2001 2005 2009 2013 2017 2021 2025 2029

Average for the decade

Annual energy elasticity

(%)


Sharp slowdown in industry sector; residential relatively robust Within sectors we expect the sharpest slowdown in energy consumption for the industry segment where we believe the rate will slowdown from an average 11.5% over 2003-10 to 2.9% over 2010-20. We expect growth to remain reasonably healthy at 4-5% until 2013. Post 2013, we expect a sharp slowdown to around 1.7-2.8% on the back of a decline in production of energy intensive products (metals and cement). From 2020-30, we expect the average growth in energy consumption by industry to be just about 1%.

However, we expect a fairly decent growth for residential and commercial sectors. While overall per capita-energy consumption in China is higher than the world average, per capita non-industrial use is still low. With rising affluence and increased importance of consumption and services in China’s future economic expansion the share of energy consumption by residential and commercial purposes will rise.

We expect residential and commercial energy to rise at a healthy 6% during 2010-20 before slowing down to around 3.3% during 2020-30.

Energy consumption growth forecasts

0

2

4

6

8

10

12

2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Industry Residential & commercial(%)


Industry segment will also slowdown in terms of

energy consumption

Residential sector will consume energy

at higher rates

We expect elasticity of energy consumption growth to decrease

Energy elasticity to drop from over

1x to 0.5x in 2020

Residential and commercial energy consumption to rise

more than industrial use



Change in proportion of energy use by various segments

56

58

60

62

64

66

68

70

72

74

2005 2010 2015 2020 2025 2030

0

2

4

6

8

10

12

14

16

18

Industry (LHS)

Transport, Storage, Post and Telecom

Residential

(%) (%)


As a result we expect the share of industry in overall energy consumption to fall from around 72% in 2010 to 67% in 2020 and 62% in 2030. Meanwhile, we expect the share of residential energy use to rise from around 11% in 2010 to 14% in 2020 and 16% in 2030.

China’s energy obesity versus rest of the world will reduce We expect China energy consumption per unit of GDP (million tonnes of standard coal equivalent per renminbi million) to come down from 92.1 in 2010 to 66.0 in 2020 and 45.9 in 2030 (all at 2009 prices). This implies a 28% decline in energy intensity by 2020 and a further 30% decline by 2030. Overall from 2010 to 2030 China’s energy intensity is likely to halve. From the peak of 2004-05 it will be down by almost 60%. Currently, China’s energy consumption per unit of PPP GDP is around 55% higher than the world average. The sharp decline in the energy intensity of the Chinese economy will help it reduce its energy obesity versus the rest of the world.

China’s energy consumption per unit of GDP (at 2009 prices)

101.2

46.0

107.9

92.1

78.1

66.0

54.9

0

20

40

60

80

100

120

140

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

(mt/Rmbbn)


Residential will consume the most energy

after 2017

Share of industry in overall energy

consumption will reduce

China energy use per unit of GDP is likely

to halve by 2030

We forecast 50% reduction in CO2

emissions per unit of GDP



China’s mix of installed power capacity

2010

Hydro21.8%

Nuclear1.0%

Coal68.6%

Others2.5%

Solar0.1%

Gas2.7%

Wind3.3%

2020

Hydro18%

Nuclear5%

Wind12%

Gas4%

Solar3%

Others3%

Coal55%

2030

Wind18%

Hydro17%

Coal42%

Others5%

Solar5%

Gas5%

Nuclear8%

China’s mix of power generated

2010

Hydro15.6%

Nuclear1.7%

Wind1.3%

Gas2.7%

WTE0.1% Other

0.9%

Coal77.7%

2020

Hydro15%

Nuclear8%

Wind6%

Gas4%

Solar1% Other

2%

WTE1%

Coal63%

2030

Wind9%

Hydro14%

Coal51%

Other3%

WTE1%

Solar2%Gas

5%

Nuclear15%


Coal will remain the king - But one with shrinking turf Despite the increase in share of non-coal power capacity, power generation through coal-based capacity will remain the largest in China in 2020 as well as 2030. However, the share of power generated from coal will shrink considerably over this period. We expect the share of coal in total power capacity to come down from 71% in 2009 to 52% in 2020 and 42% in 2030. While the portion of coal-fired capacity in total generation should come down from 78% in 2010 to 62% in 2020 and 50% in 2030.

Another interesting way to look at the changing dynamic is the share of different fuel/technologies in the new capacity added going forward. In the past decade, thermal power (primarily coal) accounted for 74% of net new installed capacity, hydropower’s share was 20%, wind 5% and nuclear had 1% share. In the next decade, we expect the share of coal to shrink to less than half at 36%, wind at 24%, hydro 14%, nuclear 9% and gas 5%. During the decade ending 2030, wind’s share in net new installations rises to 35%, followed by nuclear at 22%, hydro 14%, solar 10%, gas 7%, biomass 6% and waste to energy at 3%.

Overall, thermal and coal power capacity additions are already down from their peak of about 96GW in 2006. However, capacity additions have picked up again in 2009 after a sharp fall in 2008. Based on the capacity already under construction, we anticipate 2010 additions to be at similar levels and a gradual decline in 2011. However, we expect capacity additions to start a steady decline from 2012.

Coal will still be the most important energy resource

Coal expected to make up only 36% of new capacity

additions from 2010-20

Thermal and coal capacity additions already down

from their peak



We have assumed that the shutdown of old and inefficient capacity continues at about 10GW per annum beyond 2010. This number could be higher if the government is more strict, allowing gross capacity additions to grow at a faster pace than we are forecasting. The shutdown is likely to accelerate from 2020 as the capacity China added in the mid-1990s approaches its retirement life of close to 25 years. Towards the late-2020s, China’s coal and thermal power capacity additions are likely to turn negative as the plants added by China during its boom period after 2002 start to reach retirement age.

Gross and net thermal power capacity additions forecasts

(20,000)

0

20,000

40,000

60,000

80,000

100,000

120,0002005

2006

2007

2008

2009

10CL

11CL

12CL

13CL

14CL

15CL

16CL

17CL

18CL

19CL

20CL

21CL

22CL

23CL

24CL

25CL

26CL

27CL

28CL

29CL

30CL

(MW) Net thermal additions Gross thermal additions

Gross and net coal power capacity addition forecasts

(30,000)

(20,000)

(10,000)

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

2009

10CL

11CL

12CL

13CL

14CL

15CL

16CL

17CL

18CL

19CL

20CL

21CL

22CL

23CL

24CL

25CL

26CL

27CL

28CL

29CL

30CL

(MW) Net coal power additions Gross coal power additions

Source: CEC, CLSA Asia-Pacific Markets

Overall energy mix - Big changes ahead China’s overall energy mix is set for a big change with a fairly sharp drop in the share of coal and a rise in the share of natural gas, oil and renewable energy capacity.

Wind power will experience the highest increase in capacity share among all available technologies, rising from 3% in 2010 to 12% in 2020 and 18% in 2030. This is based on the already aggressive ramp-up in wind-power capacity additions and the fact that it is the most economic source of renewable power generation in China.

Thermal capacity set to decline

Capacity shutdown could be higher than

our estimates

Steady declines in coal capacity additions

from 2012

China’s energy mix in for a big change

Wind power will experience the biggest

rise in terms of capacity



While wind will have the highest incremental share in capacity, the technology with the biggest portion in actual power generated will be nuclear. This is because of the much higher utilisation levels for nuclear (more than 80%) compared with less than 25% for wind and solar. We expect nuclear to account for 7.9% of power generated by 2020 and 15.1% by 2030.

China’s total energy consumption trend by fuel/technology

0

1,000

2,000

3,000

4,000

5,000

6,000

2003 2006 2009 2012 2015 2018 2021 2024 2027 2030

Hydro, nuclear, wind, solar, others

Natural gas

Oil

Coal

(m tonnes of standard coal equivalent)

Share of various fuels, technologies in China’s long term energy mix

0

20

40

60

80

100

2003 2006 2009 2012 2015 2018 2021 2024 2027 2030

Coal Oil Natural gas Hydro, nuclear, wind, solar, others(%)

The use of ‘greener’ fuels/technologies is likely to rise sharply

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2003 2006 2009 2012 2015 2018 2021 2024 2027 2030

Natural gas Hydro Nuclear

Wind Solar Others

(m tonnes of standard coal equivalent)


CLSA’s energy mix forecast

Strong growth in nuclear, solar and wind

Share of wind, solar, nuclear and gas to rise at

the cost of coal

But nuclear will rise the most in terms of

power generation



We expect solar power to account for 1.2% of total power generation by 2020 and 1.8% by 2030. Natural-gas power capacity should also experience an increase in the share of power generated, from 2.8% in 2009 to more than 4% in 2020 and over 5% by 2030. We expect the share of biomass and waste-to-energy power capacity to grow from almost negligible in 2009 to 1.2% and 0.6% in 2020 then 2.3% and 1% in 2010.

While the near-term demand for coal (2011-13) is relatively robust (also supported by potential implementation of Nitrogen Oxide control norms) at around 5%, we expect a sharp slowdown from 2014 due to a steep decline in coal-fired power generation as well as a slowdown in production of steel, aluminium and cement, among others. We expect the coal demand to slow to around 2-3% in 2014-16 before slowing further to around 1% or less in the following years.

Apart from a higher share of renewable capacity and a slowdown in energy intensive industry, improving energy efficiency will be another driver for the slowdown in coal demand. We expect gradual efficiency improvements in energy intensity for most industries.

Coal demand growth rate

(%)

(5)

0

5

10

15

20

2000 2005 2010 2015 2020 2025 2030

Oil demand growth rate

(%)

0

2

4

6

8

10

12

14

16

18

2000 2005 2010 2015 2020 2025 2030


Coal will experience a sharp slowdown in

demand around 2014

Improving energy efficiency also lowers

coal demand

Share of oil in energy demand will rise

Solar will rise from a (very) small base



Unlike coal we expect the share of oil in the overall energy demand to rise. The share of oil in China’s overall energy demand is substantially lower than in other countries. However, rising vehicle penetration as well as rising share of residential energy consumption will provide a continued boost to oil demand which is expected to grow at a higher rate than overall energy demand.

We believe that China’s oil production is already close to its peak which implies that almost all of the incremental oil consumption will need to be imported. China is also experimenting with coal to liquid technologies to reduce its dependence on imported coal. However, this increases China’s dependence on coal and hence is not an ideal solution to the oil shortage. The success of these technologies will depend on oil prices and future development in technologies which can make the conversion processes cleaner and more efficient.

The table below summarises our expectation of the share of various fuels and technologies in the overall energy mix by 2020 and 2030.

Share of various fuels and technologies in China’s energy mix by 2030

(%) Coal Oil Natural gas Hydro Nuclear Wind Solar Others2010 69.8 17.9 4.2 6.1 0.7 0.5 0.0 0.8 2020 59.4 18.8 7.1 6.6 3.4 2.8 0.5 1.4 2030 48.1 21.9 8.2 6.9 7.3 4.4 0.9 2.4 Source: CEIC, CLSA Asia-Pacific Markets

With China’s energy consumption growth slowing amid economic restructuring, and an increased focus on new power supply from gas, nuclear and renewable sources, China’s thermal-coal consumption growth looks likely to remain subdued for the years ahead. Our forecasts for China’s energy consumption growth over the next ten years are for a Cagr of 4.8%, while for thermal-coal generation we only expect a Cagr of 3.1%.

With a lower demand growth rate than for coking coal, and the fact that China still has plenty of thermal-coal reserves to exploit, China should theoretically have no problem meeting its own demand growth with domestic supply. However, we believe cost pressures and tighter domestic policies on safety and environmental issues will restrict China’s domestic coal output while still encouraging imports. China will import a significant volume of coal should the global price become cheaper than its domestic cost base, as happened in 2008. That is largely dependent on China’s domestic inflation, logistics network costs, and renminbi appreciation, and is discussed in the supply section of this report.

China’s increased oil consumption will

rely on imports

Coal still the biggest fuel source at 48% of total

in 2030



Appendix 6: Global coking-coal supply by company Companies by country

(mt) Type 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

Australia

Total HCC HCC 77 75 86 95 100 100 103 103

BMA HCC 41 39 45 49 50 50 50 50

Rio Tinto HCC 9 9 9 11 12 11 11 11

Xstrata HCC 9 9 8 9 9 9 9 9

Anglo HCC 8 8 9 11 11 11 11 11

Gujarat HCC 1 1 2 2 3 3 5 5

Peabody HCC 6 5 6 7 8 8 8 8

Other HCC 4 4 5 7 8 9 10 10

Total SS SS 43 46 50 55 56 57 57 57

BMA SS 10 10 11 12 12 12 12 12

Rio Tinto SS 5 4 4 5 6 6 6 6

Xstrata SS 8 9 9 8 8 8 9 8

Anglo SS 6 6 8 9 8 8 7 7

Other SS 15 17 19 21 23 23 24 25

Total PCI PCI 19 18 23 26 29 29 30 32

BMA PCI 4 3 4 4 4 4 4 4

Rio Tinto PCI 0 0 0 0 0 0 0 0

Xstrata PCI 0 0 0 0 0 0 0 0

Anglo PCI 2 3 3 4 4 4 4 4

Macarthur PCI 5 4 5 6 6 6 6 6

Wesfarmers PCI 2 2 2 2 2 2 2 2

Yanzhou PCI 1 1 1 1 2 2 2 2

Other PCI 5 5 8 10 11 11 12 14

Total CC All 139 139 159 176 185 186 190 193

BMA All 54 52 60 64 66 66 66 66

Rio Tinto All 14 13 13 16 17 16 17 17

Xstrata All 16 18 17 17 17 17 18 17

Anglo All 17 17 20 23 23 22 22 21

Other All 38 39 49 56 63 65 69 72

Indonesia

Kangaroo Resources HCC 0 0 0 0 1 2 2 2



BHPB/Adaro HCC 0 0 0 0 0 0 1 2

Borneo Lumbung HCC 0 0 1 2 2 2 2 3

Murunda HCC 1 1 1 1 2 2 2 2

Other PCI 1 1 1 1 1 1 1 1

Continued on the next page



Companies by country (Cont’d)

(mt) Type 2008 2009 10CL 11CL 12CL 13CL 14CL 15CL

CIS

Mechel (Russia) HCC 0 0 0 1 3 7 9 9

Evraz HCC 7 8 7 7 8 8 8 8

Other SS 6 5 9 9 8 8 7 8

Mozambique

Riversdale HCC 0 0 0 0 0 0 0 2

Riversdale HCC 0 0 0 0 1 2 5 6

Posco/Talbot/NSC HCC 0 0 0 0 0 0 0 1

Vale HCC 0 0 0 0 2 3 5 7

Coal India HCC

Other Africa

CoAL (South Africa) na 0 0 0 0 0 1 2 3

CoAL (South Africa) SS 0 0 0 1 1 1 3 5

Keaton SS 0 0 0 0 0 0 0 0

Exarro SS 0 0 1 1 1 1 1 1

Mongolia

MCC HCC 2 2 4 6 8 11 14 15

South Gobi SS 1 0 2 3 4 4 4 4

South Gobi SS 0 0 0 0 1 3 5 5

Mongolia Energy SS 0 0 1 2 4 5 6 6

Energy resources HCC 0 2 4 5 6 7 8 8

Nariin Sukhait SS 1 2 2 2 2 3 4 4

Other SS 1 0 1 1 1 1 1 1

Canada

Teck HCC 19 18 19 22 24 25 25 25

Teck PCI 2 2 2 2 2 2 2 2

Western coal HCC 2 2 2 3 4 4 4 4

Western coal PCI 1 1 1 2 2 2 2 2

Grand Cache HCC 2 1 2 3 3 3 4 4

PRC HCC 2 1 1 1 2 3 4 4

Kailuan HCC 0 0 0 0 1 1 2 2

USA

Massey HCC 6 6 6 8 11 11 11 11

Alpha natural resources HCC 6 5 5 5 6 6 6 6

Patriot HCC 2 2 3 3 4 4 4 4

Walter HCC 6 9 9 10 10 10 10

Metinvest/UCC HCC 1 1 1 1 1 1 1 1

Consol HCC 3 2 6 6 7 7 7 7

Mechel HCC 1 1 3 3 4 4 4 4

Arch SS 3 2 5 5 5 6 6 6

Cliffs HCC 2 1 3 4 4 4 4 4

Drummond HCC 2 2 2 2 2 2 2 2

Other small mines HCC 5 5 7 8 9 9 9 9

Source: Company reports, industry sources, CLSA Asia-Pacific Markets

Coal outlook


Notes

Important notices

27/08/2010

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Malaysia (60) 3 2056 7852 Philippines (63) 2 860 4030 Singapore (65) 6416 7878 Taiwan (886) 2 2326 8124 Thailand (66) 2 257 4611 UK (44) 207 614 7260 US (1) 212 408 5800

© 2010 CLSA Asia-Pacific Markets ("CLSA"). Key to CLSA investment rankings: BUY = Expected to outperform the local market by >10%; O-PF = Expected to outperform the local market by 0-10%; U-PF = Expected to underperform the local market by 0-10%; SELL = Expected to underperform the local market by >10%. Performance is defined as 12-month total return (including dividends). 14/09/2010

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