International Coal Market & Policy Developments in 2009 · PDF file4.1.2 CIAB Members...

COAL INDUSTRY ADVISORY BOARD

International Coal Market & Policy Developments in 2009

FEBRUARY 2010

Contents

FORWARD FROM CIAB CHAIRMAN 0

1 HIGH LEVEL MESSAGES 1

1.1 CIAB Policy Advice 1

1.2 The Role of Coal in World Energy Markets 4

2 CIAB WORK PROGRAMME 6

2.1 Achievements in 2009 6

2.2 Future Work 8

3 OVERVIEW OF WORLD COAL MARKET DEVELOPMENTS 9

3.1 Coal Reserves and Production 9 3.1.1 Hard Coal 12 3.1.2 Brown Coal 14 3.1.3 Company Developments 15

3.2 Coal Consumption 18 3.2.1 Total Hard Coal Consumption 18 3.2.2 Thermal Coal Consumption 20 3.2.3 Metallurgical Coal Consumption 23 3.2.4 Brown Coal Consumption 24 3.2.5 Company Developments 25

3.3 Trade and Prices 26 3.3.1 Freight Market 26 3.3.2 Trade Volume 27 3.3.3 Market Prices 30

4 ISSUES RELATED TO COAL 32

4.1 CIAB Plenary Meeting Discussion 32 4.1.1 Emerging Themes 32 4.1.2 CIAB Members Questionnaire 33

4.2 Sustaining the Role of Coal 36 4.2.1 Policy and the Role of Coal 36 4.2.2 Greenhouse Gas Reduction Measures and Emissions Trading 41 4.2.3 Power Station Emissions Control/Mining Regulations 48

4.3 Investment in Coal Supply, Transportation and Use 50 4.3.1 Investment Overview 50 4.3.2 Specific Investment Plans and Projects 50

4.4 Developments in Clean Coal/Near Zero Emissions Technology 57

5 CONCLUDING REMARKS 62

Author’s Note: The report has been compiled on behalf of the CIAB by Brian Heath, CIAB Executive Co-ordinator, and thanks are due to the following CIAB Associates, on whose contributions it is substantially based: Mick Buffier* Xstrata Coal Australia

Ross Willims BHP Billiton Mitsubishi Alliance Australia

Tom Pierce Grand Cache Coal Corporation Canada

Kevin Stone Natural Resources Canada Canada

Sylvie Cornot-Gandolphe ATIC Services France

Maggi Rademacher* E.ON Kraftwerke Germany

Hans-Wilhelm Schiffer RWE Germany

Martin Wedig German Hard Coal Association Germany

Takenori Iwasaki* J-Power Japan

Alison Brown Solid Energy New Zealand

Stan Pillay* Anglo Coal South Africa

Antonio Canseco Fuelec S.L. Spain

Mücella Ersoy TKI Turkey

Anna Belova SUEK Russia

Robin Irons E.ON Engineering UK

Tim Marples UK Coal UK

Ron Engleman Leonardo Technolgies USA

Connie Holmes* Consultant to NMA USA

Cartan Sumner Peabody Energy USA

* These contributions are consolidated and include contributions from other CIAB Associates in that country The sections of this report reviewing world coal supply and demand draw on a consistent coal data set provided by the IEA. At the time of writing, the latest such data available refer to 2008 and are based on preliminary estimates made by IEA Member governments. Where firmer or more recent data are available from CIAB Associates or other sources, these are used and any significant variations from IEA data are highlighted. Thanks are also due to The McCloskey Group for permission to use their coal price data and to the Chicago Climate Exchange for permission to use their trading data. The use of website links included in this report is subject to the Terms and Conditions set out in those websites. This report represents the personal views of the individual contributors and does not necessarily represent the views of their companies, organisations or of the IEA.

FORWARD FROM CIAB CHAIRMAN The Coal Industry Advisory Board (CIAB) is a group of high level executives from coal-related industrial enterprises, established by the International Energy Agency Governing Board in July 1979 to provide advice to the IEA from an industry perspective on matters relating to coal. There are currently 42 CIAB Members from 20 countries, typically Chief Executives or senior executives from coal mining, transportation and machinery companies, or from major power generation or other coal consuming companies. The original task of the CIAB was to assist the IEA in the practical implementation of the “Principles for IEA Action on Coal” – measures aimed at ensuring a ready supply and trade of coal to underpin energy security. In recent years the CIAB has focused additionally on developments in the technology of coal use required to enable coal to contribute to energy security in this era of climate change concern; and on issues arising from increasingly liberalised energy markets, such as the restructuring and privatisation of coal and electricity industries in many countries. The CIAB produces this report annually for the Governing Board, Standing Committees and Secretariat of the International Energy Agency. It draws on contributions from Associates of CIAB Members to briefly describe developments in international coal markets over the last year and to highlight policy and other issues that CIAB Members regard as pertinent to the development of coal as a secure, clean and competitive energy source. We hope that it will also be of interest to a wider audience. Roger Wicks CIAB Chairman February 2010

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1 HIGH LEVEL MESSAGES

1.1 CIAB Policy Advice 1. IEA energy scenarios1 predict rising global energy demand and a continued reliance on

fossil fuels for the next twenty years. They further illustrate the necessary role for coal in a sustainable energy future, to fuel the rapidly developing electricity and energy needs of developing economies and to contribute to global energy security. China and India now account for nearly half of global coal demand; while 97% of the projected increase in coal demand2

2. In the short term, despite the effects of the global financial crisis and economic downturn, worldwide coal use is still growing more rapidly than total energy use and this is particularly evident in countries such as China and India. Even the WEO 2009 450 Scenario shows substantial growth in coal use to 2020, although a rapid substitution of nuclear and renewal electricity generation is projected to occur in the subsequent ten years. Coal is much more plentiful than oil and gas and is much more widely distributed, providing a secure energy supply that is inherently less susceptible to disruption than oil or gas.

occurs in non-OECD countries, mainly Asia. At present 25% of the world’s population, concentrated in developing countries, does not have access to electricity and a similar proportion only has access to intermittent supplies.

3. The CIAB recognises this role for coal, and the strength of the desire for secure energy supplies in developed and developing economies. Currently, coal mining investment in developed economies is being discouraged by uncertainty over future carbon regulatory regimes and clarity is required. Governments have important roles in providing stable, effective and predictable regulatory frameworks and in ensuring that incentives for long-term investment in coal supply and use are in place.

4. Modern, state-of-the-art coal-fired power plants have CO2

5. The future use of increasing quantities of coal worldwide is necessary, certainly over the next ten years and possibly well beyond, if the world is to avoid a damaging energy crunch and is to support the development needs of poorer nations. However, coal is the most CO

emissions up to 40% lower than the average for all coal plants. However, in developed economies where electricity growth is low and the use of other fuels is an option, many coal-fired electricity generation projects are currently stalled, jeopardising future electricity supply security. In developing economies the use of coal for power generation is interwoven with economic development goals. These goals, together with information, skills, cost and risk issues, may sometimes conflict with installing state-of-the-art technology.

2 intensive fossil fuel and is responsible for over 40% of all energy related CO2 emissions.

6. Basic research needs to be encouraged, and no possible option for reducing greenhouse gas (GHG) emissions can be ignored, although many governments now appear to recognise that carbon capture and storage (CCS) technology is currently the most promising option for reconciling the continued use of fossil fuels, and in particular coal, with GHG reduction objectives. However, slow progress on this front remains of concern to the coal industry. Bridging the commercial gap and addressing the commercial risks of

Therefore it is clear that greenhouse gas emissions associated with the use of coal must be significantly reduced while maintaining the ability to meet future coal demand.

1OECD/IEA “World Energy Outlook 2009” (2009) 2OECD/IEA “World Energy Outlook 2009” (2009) Reference Scenario

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first-of-a-kind projects are essential steps in the development of the initial portfolio of CCS demonstration projects.

7. The rapid growth of coal use for electricity generation in developing economies makes those countries an important focus for CCS deployment. Electricity generating capacity installed now could have a life expectancy of 40 years, with the potential to lock in unnecessarily high levels of CO2

8. Large scale demonstration programmes could be encouraged in developing countries, where incremental costs are supported and local capacity is developed. Studies on some of the fundamental issues such as CCS storage potential and reducing the energy intensive nature of capture need to be fast-tracked in order to address the understanding of local potential. Support also needs to be made available for specific country based studies on making coal plant capture ready.

emissions. But often the cost penalties of the efficiency reduction associated with CCS-equipped power plants, together with the lack of GHG emissions reduction mechanisms to recover some of the costs, act as deterrents to the deployment of CCS.

9. The IEA needs to look at a suite of suitable policy approaches so that greenhouse gas emissions mitigation and climate change adaptation objectives are integrated, e.g. link climate change, energy, water and economic development policies. Adaptation, for example to extreme weather events and water scarcity, is important for ensuring robust electricity supply systems and will be addressed further in the CIAB’s 2010 report.

10. The Clean Development Mechanism (CDM) can currently be utilised to improve the efficiency of existing plant and more effort should be put into identifying and fast-tracking suitable projects. The current CDM mechanisms do not support required levels of R&D and technology transfer and thus, post 2012, new approaches need to be identified and rolled out in developing countries. The IEA could play a role in developing benchmarking methodologies in support of sectoral-based approaches.

11. Many of the above issues were addressed by the CIAB in its statement prepared well in advance of the COP15 meeting held in Copenhagen in December 20093

1. The post-2012 GHG reduction agreement must play a central role in delivering the technologies and best practices, and also the research and development, that enable deep reductions in CO

. The key elements that the CIAB believes governments must include in the new agreement are:

2

2. Crediting mechanisms are needed to incentivise the deployment of high-efficiency coal-fired power plants.

emissions from coal use, while maintaining adequate coal supply.

3. Significantly increasing investment in the development and deployment of Carbon Capture and Storage (CCS) technology should be an immediate priority and a key goal of the post-2012 climate agreement.

4. CCS must be incorporated into the post-2012 low-carbon technology crediting mechanisms.

5. A CCS deployment fund should be established to demonstrate commercial scale coal-fired power plants with CCS in a variety of developing countries.

3 “The Role of Coal in the Post-2012 Greenhouse Gas Reduction Agreement”, CIAB, 4 September 2009

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6. Mechanisms must be developed to allow the large number of coal fired power plants currently being built in developing countries to be constructed as ‘CCS-Ready’.

7. Capacity building and knowledge sharing programmes must be implemented to ensure that the operation and maintenance of plants and adaptation efforts follow international best practice, and that the implementation of CCS projects worldwide can benefit fully from the experience of early investments.

8. Clarity over crediting mechanisms for biomass sequestration and linked financial benefits for forest and eco-system protection and restoration could play a major role in driving additional CO2 sequestration while contributing significantly to poverty reduction.

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1.2 The Role of Coal in World Energy Markets 12. The world’s coal reserves are extraordinarily large and widely dispersed. Coal is safe and

easy to transport, and it can be readily stored. Reflecting these attributes, as well as the reserves base of developing economies including China and India, coal use is now growing at a higher rate than other fossil fuels.

13. According to IEA figures, over the years between 1980 and 2007 world primary energy demand has grown by 1.90% per year and, despite the rapid growth in use of oil and gas, coal demand has grown at a higher rate of 2.15% a year on average. Moreover, the historical trend in coal consumption has accelerated recently, growing by over 4% a year on average over the last ten years and over 6% on average over the last five years.

14. Total world primary energy consumption4

15. For the first time in fifteen years, thermal coal trade failed to grow in 2008, declining marginally to 676 million tonnes of which 606 million tonnes was traded by sea. However, over the last 10 years, seaborne thermal coal trade has still doubled, with average annual growth of 31 million tonnes (7.5%) per year.

grew by 1.4% in 2008, while growth was 7.2% in China and 5.6% in India. World consumption of coal again grew more strongly (3.4%) than total energy use. Coal accounts for 70% of China’s energy consumption and 53% of India’s energy consumption. Despite the onset of the global downturn in the latter half of 2008, these economies have continued their rapid growth in energy consumption and reliance on coal.

16. Australia remains by far the largest hard coal (thermal and metallurgical coal) exporting country with 252 million tonnes of exports, or nearly 27% of the world market, in 2008. Indonesia was second with 203 million tonnes (21.6% of the world market). However, Indonesia is the largest exporter of thermal coal.

17. In its Reference Scenario5, the International Energy Agency expects total world primary energy use to grow by 1.5% a year to 2030 and coal use to grow by 1.9% a year. Historically, coal has accounted for 24-26% of world energy use: this is now expected to increase to over 29% in the Reference Scenario. Even in the 450 Scenario, which analyses how global energy markets could evolve if countries take co-ordinated action to restrict the global temperature increase to 2o

18. With appropriate policy and investment signals, coal has the ability to meet long term increases in demand, to support economic growth and to enhance the security of world energy markets through the development of national coal resources and increased international trade. However, coal mining investment in developed economies is currently being discouraged by uncertainty over future carbon regulatory regimes and clarity is required. In addition, the pause in new capacity investment in response to the global financial crisis and the economic downturn raises the possibility that energy supplies may prove to be inadequate in the short term as world economies eventually recover. Moreover, the coal industry will need to increasingly adapt to climate change impacts on weather, water and infrastructure to ensure that it remains a reliable source of energy.

C, coal use increases to 2020, before declining by 3% per year to 2030, accounting for 18% of energy needs in that year.

19. Into the longer term, greenhouse gas emissions associated with the use of coal must be significantly reduced while maintaining the ability to meet future coal demand. Those negotiating a post-Kyoto climate change agreement must be encouraged to focus on

4 Figures in this paragraph are derived from “BP Statistical Review of World Energy June 2009” 5 OECD/IEA “World Energy Outlook 2009” (2009)

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catalysing the development and deployment of technologies including, but not restricted to, carbon capture and storage (CCS) and best practices that reduce coal related emissions.

20. Carbon capture and storage is an indispensable tool in addressing the greenhouse gas emissions concerns that are associated with the continued use of fossil fuels but, acting alone, the market is unlikely to deliver the required technological “step changes”; they generally require public support.

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2 CIAB WORK PROGRAMME 2.1 Achievements in 2009 21. During 2009, the CIAB has focussed less on preparing specific reports and more on

widening its interface with members of the IEA Secretariat and external organisations. Ben Yamagata, CEO of the USA Coal Utilization Research Council (CURC) attended the CIAB Associates February 2009 meeting in Washington DC. CURC’s focus is primarily on CCS and it was agreed that the two organisations should maintain close contact. The CIAB is also working more closely with various individuals in the CIAB Secretariat, the IEA Greenhouse Gas R&D Programme (IEA GHG), the IEA Working Party on Fossil Fuels (WPFF) and the Global Carbon Capture and Storage Institute (GCCSI).

IEA Greenhouse Gas R&D Programme

22. Following endorsement from the CIAB Executive Committee and Members attending the 2008 Plenary meeting, the CIAB became a formal Sponsor of IEA GHG in 2009. A CIAB representative now attends IEA GHG Executive Committee meeting and the interface is managed through a small group of CIAB Associates led by Mr. Alex Zapantis, Associate to CIAB Member Mr. Preston Chiaro. The group’s aim is to influence the IEA GHG work programme by submitting ideas for IEA GHG Executive Committee consideration, encourage CIAB participation in IEA GHG events, co-ordinate responses to draft IEA GHG reports, and to disseminate IEA GHG reports and other output to CIAB Associates and then into the relevant parts of their organisations.

The Role of Coal in the Post-2012 Greenhouse Gas Reduction Agreement

23. At their meeting in November 2008, the CIAB Executive Committee suggested that the COP15 meeting in Copenhagen in December 2009 should provide a focus for CIAB policy messages. The IEA has no formal place at this meeting, although it maintains a strong presence at the venue and its views are well respected. Accordingly, the CIAB produced a statement “The Role of Coal in the Post-2012 Greenhouse Gas Reduction Agreement”, which was submitted to the IEA Executive Director by the CIAB Chairman on 4 September 2009.

Plenary Meeting discussion sessions

24. In order to widen the discussion of topics relevant to coal with senior representatives of the IEA, CIAB Members and others made a series of presentations at the November 2009 CIAB Plenary meeting. The presentations and discussion were arranged into three discussion sessions:

• Greenhouse Gas Mitigation Measures – Implications for the Coal Industry in Developed and Developing Economies;

• Energy Sector Investment and the Coal Industry – Implications for Energy Security; and

• Carbon Pricing – Implications for Coal and the Migration of Industrial Activity. 25. A note of these discussions is available on the CIAB website (www.iea.org/ciab). A

questionnaire was issued to CIAB Members in advance of the meeting and the responses collated as an aid to the discussions; and to ensure that all Members had the opportunity to have their views recorded. The main points from the Plenary meeting discussions and the questionnaire responses are set out in Section 4.1 of this report.

http://www.iea.org/ciab�

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Leading Practice Working Group

26. A CIAB paper “Reconciliation of Coal Fired Power Plant Efficiencies” was completed and submitted to the IEA in April 2008. It was intended that this major piece of technical work, exploring the many issues that influence reported efficiency figures and presenting a methodology for reconciling these as an essential pre-requisite for comparison with leading practice, should be published as part of an IEA report targeted at promoting improvements in coal-fired power generation technology. However, on further consideration, it has now been agreed that it should be published as a stand alone CIAB report. Work on this has been on-going during 2009, with publication targeted for early in 2010.

Clean Coal Technologies Working Group (Chair – Deck Slone)

27. In July 2008 the G8 leaders, meeting in Hokkaido, endorsed the IEA recommendations for the development of 20 integrated large-scale CCS projects by 2020. It is clear that first-of-a-kind commercial risks are currently a major barrier to the achievement of this objective. Accordingly, the IEA Working Party on Fossil Fuels (WPFF), the Coal Industry Advisory Board (CIAB), the Carbon Sequestration Leadership Forum (CSLF) and the Global Carbon Capture and Storage Institute (GCCSI) collaborated in the organisation of a workshop “Carbon Capture and Storage (CCS): Bridging the Commercial Gap”, held in New York on 29th - 30th

28. First-of-a-kind commercial risks are currently a major barrier to the development of 20 integrated large-scale CCS projects by 2020. Accordingly, the workshop objectives were to develop recommendations to:

September 2009.

• bridge the commercial gap by considering what mechanisms available to governments are best suited to provide the public funding necessary to launch the initial 20 large-scale CCS demonstration projects; and

• narrow the commercial gap by considering what investment risk management measures governments can take, thereby reducing the requirement for public funding.

29. The CIAB contributed to the development of the initial workshop recommendations into

more detailed recommendations for submission to the G8 meeting in Canada in June 2010.

30. The CIAB provided comments on the draft IEA CCS Roadmap which was published on 13 October 2009.

Energy Security Working Group (Chair – Hans-Wilhelm Schiffer)

31. In support of IEA work on Energy Security Benchmarking, the working group arranged for Dr. Manuel Frondel from the German scientific institute RWI to meet with the IEA in March to explain the institute’s methodology for measuring energy supply risks and the results of its specific country analysis.

32. A major focus of IEA work during 2009 has been the effects of the Financial Crisis on energy investment, reflecting the organisation’s concern that reduced investment may lead to higher energy prices as economies recover. The CIAB, through the Energy Security Working Group, has supported that effort during 2009.

33. Publicly available coal company information was researched and supplied to the IEA by several CIAB Associates. Interim conclusions of the analysis were incorporated into an

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IEA background paper for the G8 Energy Ministers’ meeting on 24/25 May, and the work was further refined by the IEA as input to “World Energy Outlook 2009” and other IEA publications. During that process of further refinement, the CIAB Chairman wrote to CIAB Members encouraging support of a request from the IEA to review coal industry data and information and to provide commentary on the analysis.

34. Under the auspices of the working group a meeting was arranged following the November 2009 Plenary meeting, at which Dr. Moritz Paulus of the Institute of Energy Economics at Cologne University (EWI) introduced a new project to model the international thermal coal market.

2.2 Future Work 35. Work in 2010 will include preparation of the annual CIAB report “International Coal

Market & Policy Developments in 2010” and support for specific IEA coal initiatives. One such initiative is a workshop on energy efficiency and clean coal technologies to be held in Moscow during 2009. The initiative flowed from a joint statement issued by the IEA and the Russian Ministry of Energy following the IEA Governing Board meeting at Ministerial Level in October 2009. The CIAB will participate in the planning and execution of the workshop.

36. The CIAB will also participate in the specification and management of a proposed study on the global socio-economic value of coal.

37. Central to consideration of further CIAB work is the issue of balancing energy supply security and expectations of significantly increased coal use with the need to mitigate the concomitant growth of CO2

38. The work of the Energy Security Working Group and the Clean Coal Technologies Working Group will continue in 2010 with specific work programmes to address relevant issues.

emissions, brought into focus by the IEA’s “World Energy Outlook” energy demand projections.

39. Given the accepted future role for carbon capture and storage (CCS) the CIAB is aware of the need to encourage greater involvement by the coal industry in CCS issues. In 2010 the CIAB will continue its sponsorship of the IEA Greenhouse Gas R&D Programme (IEA GHG) and collaboration with other organisations.

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3 OVERVIEW OF WORLD COAL MARKET DEVELOPMENTS 40. According to BP statistics6

, world consumption of primary energy grew by 1.4% in 2008 (2.6% in 2007), despite the onset of the global financial crisis and the economic downturn. Within this total, the Asia Pacific region increased its energy consumption by 4.1% (5.5% in 2006).Energy consumption in China grew by 7.2%, and in India by 5.6%, with China showing slightly lower growth in coal consumption (6.8%) and India higher (8.4%). Global coal consumption again grew much more strongly (3.1%) than total primary energy use. It is notable that coal accounts for more than 70% of China’s energy consumption.

3.1 Coal Reserves and Production 41. Germany's Federal Institute for Geosciences and Natural Resources (BGR) produce

estimates of coal resources and coal reserves. “Resources” are that amount of energy resources which are either (i) proved but at present not economically recoverable, or (ii) geologically indicated. For coal this term is used for all resources in-place (in-situ). “Reserves” are that amount of energy resources, which is known in detail and can be recovered economically using current technology. Reserve estimates therefore depend on price as well as on technological progress.

42. Total resources (resources and reserves) of hard coal and lignite are estimated by BGR at some 21 trillion tonnes at end-2008. Most of this (79%) is hard coal at 16,383 gigatonnes (Gt), with 4,384 Gt (21%) for soft brown coals. Of the total hard coal resources figure, some 15,655 Gt, or more than 95%, are classified as resources and 728.4 Gt (4.4%) as reserves.

43. The United States of America has 41% (almost half being in undeveloped regions of Alaska), China has 32% and Russia has 17% of hard coal resources. Asia, North America and the CIS account for 86% of hard coal reserves, of which 36% are in Asia (almost exclusively China and India), 33% in North America (almost exclusively the United States), and 17% in the CIS.

44. Most of the lignite resources are located in only three regions: North America, the CIS and Asia. About one third of global lignite resources are located in North America (35%) and in the CIS region (31%). The largest lignite resources are in the United States (33%), Russia (31%) and China (8%).

45. The concentration of lignite reserves is lower than that for hard coal. Most are located in the CIS, Russia predominating with 34% of the global total. Europe has the second-biggest lignite reserves (25%), most of which (15%) is in Germany. Oceania has the third-largest reserves (16%), with Australia accounting for 14%. The United States and China have 12% and 4% respectively.

46. The BGR estimates show that coal reserves would be sufficient to cover current global coal production for approximately 125 years (270 years in the case of lignite), far higher than for natural gas or oil.

47. According to IEA estimates for 20087

6 2008 growth rates have been adjusted to remove the leap year effect

, worldwide coal supply increased by 310 million tonnes coal equivalent, or 6.8%, in 2008, with Chinese supply growing by 13% to account

7 Growth rates not adjusted to remove the leap year effect - adjustment would remove 0.3% growth.

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for over 240 million tonnes coal equivalent of the increase.

48. In the United States of America, total coal production in 2008 was a record 1.171 billion short tons (1.062 billion tonnes), an increase of 24.9 million tons or 2.2% on 2007 production. Estimated lignite production was 74.2 million tons (67.3 million tonnes), implying that production of bituminous and sub-bituminous coals totalled 1.097 billion tons (995 million tonnes). Production was up or steady in all regions of the country: by 3.2% in Appalachia, ending a two year decline in production in this region, by 2.0% in the western states and by less than 1% in the Interior region. The slow rate of growth in the Interior region was due to a decline in lignite production in Mississippi and Texas.

49. Wyoming remained the largest coal producing state with 467.6 million tons (424.2 million tonnes) or 40% of national production. West Virginia was again the second largest coal producing state (157.0 million tons, 142.4 million tonnes) and Kentucky remained third (119.9 million tons, 108.8 million tonnes). All eastern states except Tennessee and Virginia experienced increases in production, in part due to demand for metallurgical coal for export. All major coal producing states in the west except Colorado, where there were production problems in two major mines, showed increases. It should be noted that in the last half of 2008 production exceeded consumption in most months and as a result inventories increased to near record high levels by the end of 2008.

50. In the first part of 2009 the steep decline in demand for coal use at electricity generating plants and for coking, coupled with a decline in demand for US coal for export (see below) and already high inventories, mean that coal production for the whole of 2009 is expected to decline to 1.074 billion tons (974 million tonnes)8

51. Through to September 2009 total coal production was down 6.3% compared with the same period in 2008. Production is down in Appalachia and in the western regions of the country, while production is up slightly in the interior region, due mainly to increases in production in Illinois, Indiana and West Kentucky. Declines in the major coal producing states were: Wyoming 25.6 million tons (-7.4%), West Virginia 10.0 million tons (-8.5%), Eastern Kentucky 7.5 million tons (-10.9%). Inventories will be at all time highs at the end of 2009.

. The projected 8.4% percent decline, nearly 100 million tons, would be the greatest percentage decline in many years and the largest absolute tonnage decline ever experienced.

52. Canada holds 8.7 billion tonnes of proven coal reserves, including 6.6 billion tonnes of proven recoverable coal reserves, which will provide more than 100 years of production at the current production rate. In addition, about 193 billion tonnes of coal resources have been identified. Most large-scale coal mines are located in western Canada. Twenty-two coal mines were in operation at the end of 2008 and two mines were idled. Four companies produce metallurgical and PCI coal for exports, two companies produce bituminous thermal coal for export and domestic use, and three companies produce sub-bituminous, lignite and bituminous coal for domestic coal-fired power generation.

53. Preliminary figures indicate that Canada produced 68.1 million tonnes of coal in 2008, or 1 million tonnes less than the 69.1 million tonnes produced in 2007. About 34 million tonnes of coal was hauled by rail and approximately 53 million tonnes was handled by ports in 2008. Alberta produced 31.5 million tonnes, British Columbia 26.6 million tonnes, Saskatchewan 10 million tonnes and New Brunswick and Nova Scotia each produced a limited amount.

54. Of the total coal production, 26.7 million tonnes was metallurgical coal for export, about 5.6 million tonnes was bituminous thermal coal for export and 36.5 million tonnes was

8 US Energy Information Administration forecast, late September 2009

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thermal coal for domestic coal-fired power generation use. Most of the output in the metallurgical coal category was hard coking coal and a small portion was PCI coal. The majority of the thermal coal was sub-bituminous and lignite coal, although more than 10% was a bituminous-grade thermal coal.

55. Australia is the world’s largest coal exporter and also utilises coal domestically largely for power generation where around 80% of electricity is generated in coal-fired plant. In 2008 a total of 411.5 million tonnes of coal was produced with exports of 260.5 million tonnes or 63% of total production. In 2009 the Australian Government’s key energy forecaster ABARE estimated total production of hard coal would increase by 3% to 334 million tonnes in 2009, with exports of 250.5 million tonnes.

56. Coal in Australia is produced from a total of 128 operating mines, 68% of which utilise open cut methods with the balance underground operations. The vast bulk of coal, and nearly all exported coal, are produced in the states of New South Wales and Queensland with production in Victoria, South Australia, Western Australia, and Tasmania used for domestic consumption.

57.

58. New Zealand

Expansion of and access to infrastructure for exporting coal has been a significant factor in restricting growth of coal exports in Australia over the last few years. Significant investment in rail and port infrastructure - both planned and already underway - should allow increases in export capacity and overall production over the next few years

9

59. New Zealand has 26 operating coal mines - four underground and 22 opencast mines. Over 60% of national production is from two large opencast operations, at Rotowaro and Stockton, and a further 16% from New Zealand's two largest underground mines, Huntly East in the Waikato and Spring Creek at Greymouth. Solid Energy New Zealand Ltd is New Zealand's largest coal producer, producing over 80% of New Zealand's total coal production. About 2 million tonnes of mainly bituminous coal is exported annually.

has extensive coal resources, mainly in the Waikato and Taranaki regions of the North Island, and the West Coast, Otago and Southland regions of the South Island. Total in situ coal resources are estimated at around 15 billion tonnes of which, approximately 9 billion tonnes is judged to be economically recoverable. Recoverable ignite deposits are estimated at over six billion tonnes. Sub-bituminous and bituminous in-ground resources are about 3.5 billion tonnes, although there is some uncertainty how much of this is recoverable. Although lignite makes up 85% of national coal resources, almost all production is of bituminous and sub-bituminous coals.

60. Coal production in the year to September 2008 was 5.13 million tonnes, an 11.5% increase on the previous year, although in the subsequent six months production was 9% lower than in the same period of the previous year.

61. In Russia, the coal industry comprises companies which are smaller than the state-controlled Gazprom (oil and gas), nuclear and hydropower companies and it is more competitive

62. According to BP Statistical Review of World Energy 2009, Russian proved coal reserves at the current production rate (2008) will last 481 years, compared with 22 years for oil

. Some coal companies are seeking external support to invest in CCS and other clean-coal technologies. The Siberian Coal Energy Company (SUEK) is a leading player, producing mainly thermal coal which is distributed to Russian power utilities or is exported to European and Asia-Pacific coal markets. In recent years, Russian coal producers have invested heavily in modernization of their production facilities, improving mine productivity and safety.

9 data from “New Zealand Energy Data File June 2008”, Ministry of Economic Development, © Crown Copyright 2008

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and 72 years for natural gas.

63. The Russian Federal State Statistics Service (ROSSTAT) reports Russian coal production of 326.5 million tonnes in 2008, of which 246 million tonnes was hard coal (143 million tonnes opencast and 103 million tonnes underground mines) and 80.5 million tonnes was brown coal (79 million tonnes opencast). 66 million tonnes of the hard coal was metallurgical coal. In comparison with 2007, coal production increased by 3.9% in 2008. Opencast mining of hard coal increased by 5.2% while underground mining of hard coal dropped 3.5%. Brown coal production rose 12.6% in 2008. The production of metallurgical coal decreased by 6.6% in 2008.

64. According to ROSSTAT statistics, coal production in the first half of 2009 totaled 137.2 million tonnes, 14.8% lower than in the first half of the previous year, while the June 2009 figure was only 7.6% lower than in June 2008.

65. One specific example of the effects of the global financial crisis on the Russian coal industry is that the global steel maker ArcelorMittal, which operates three coal mines in Kemerovo province in central Russia, is now seeking to cut production and headcount at the mines, which employ about 6,000 people.

66. Before the financial crisis there was a shortage of rail cars for coal transportation in Russia, although this has been temporarily alleviated. In the first half of 2009 hard coal loaded to rail was 14% lower than in the first half of 2008 and the total volume of rail car loading showed a 23% reduction. However, there is concern that the problem will recur as the Russian economy recovers.

67. Structural reform of Russian railways continues, with the aim of moving from the Russian Railways monopoly to a competitive rail services market which will improve efficiency and profitability and encourage investment in railway modernization. The end of the current (final) third phase of this reform is planned for 2010, when more than 60% of the locomotive and railway carriage fleets will be privatized in Russia.

3.1.1 Hard Coal 68. World hard coal production has continued to grow strongly over the last eight years, with

the 2008 level over 60% higher than in 2000, a rate of growth averaging over 6% a year. Nearly 70% of this 2.2 billion tonne growth was accounted for by China.

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© OECD/IEA, 2009

69. According to IEA estimates, world hard coal production grew by over million tonnes

(7.4%) to 5.85 billion tonnes in 2008. Chinese coal production grew by 12% to 2.76 billion tonnes, while Indian production grew by 7.7% to 489 million tonnes and Indonesian production grew by nearly 7% to 246 million tonnes. In contrast, Australian production grew by less than 1% to 325 million tonnes and OECD production (28% of the world total) grew by only 1%.

Table 1 - Hard Coal Production (million tonnes)

2006 2007 2008em.tonnes m.tonnes change m.tonnes change

EU(19) 154 146 -5.5% 135 -7.1%OECD 1500 1510 0.7% 1525 1.0%World 5209 5442 4.5% 5845 7.4%

© OECD/IEA, 2009

70. Australian hard coal production was 339.1 million tonnes in 2008, a 5% increase on 2007, of which 260.5 million tonnes or 77% was for export. 193.5 million tonnes (57% of the production) was thermal coal. The bulk (97%) of black coal was produced in Queensland and New South Wales for domestic and international markets, with the balance produced for domestic markets only in South Australia, West Australia and Tasmania. The bulk of production (75%) was from surface mines with underground mines contributing 25%.

71. In South Africa, there is approximately 30 billion tonnes of minable reserves in-situ, although infrastructure weaknesses, especially rail, and the distance of reserves from ports constrain competitiveness in the export markets. However, increased domestic power station and export demand will once more create the opportunity for old and new coal mines to increase production.

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72. About 51% of South African coal mining is done underground and about 49% is produced by opencast methods. 252 million tonnes of coal was produced in 2008 (IEA estimate 236 million tonnes), of which bituminous coal is 99% and anthracite is 1%. Coal mines discarded 64 million tonnes of waste or discard coal.

73. In 2007, 83% of the saleable coal production was supplied by mines controlled by the five largest mining groups (Anglo Coal, Exxaro, BHP Billiton, Sasol, and Xstrata).

74. During the power crisis in 2008, the Mining industry’s electricity off-take was cut back by 10% and it is still operating on this rationed basis.

75. There is a continuous search by economic empowerment entrepreneurs for viable blocks of reserves to establish new mines, assisted by the Mineral and Petroleum Resources Development Act and the Mining Charter. A number of large Historically Disadvantaged South African (HDSA) mining companies, previously only involved in gold, diamonds and platinum mining, are exploring brown-field and green-field opportunities in coal. Some of these companies have made agreements with existing independents and are waiting for opportunities to grow.

76. German coal mines are all scheduled to close at intervals by 2018. The restructuring program continued during 2008 and 2009; but the phase-out plan is scheduled for review again in 2012, when further options are likely to be discussed for a continuation of German hard coal production.

77. Hard coal production fell by 5 million tonnes to 19 million tonnes due to the closure of the Walsum mine in June 2008 and reduced output from Ensdorf, Lippe, Ost and Ibbenbüren. The Lippe mine was closed at the beginning of 2009 and hard coal production is forecast to fall again in 2009 to about 15.5 million tonnes. The Ost mine is scheduled to close in September 2010 and the Ensdorf mine in June 2012.

78. German thermal coal imports for power stations totalled 33.16 million tonnes in 2008, a 5% increase on 2007.

79. In the United Kingdom provisional figures for 2008 show that coal production increased by 5.3% to 17.9 million tonnes, with deep mined production increasing by 4.7% and opencast production by 6.3%. 15 underground mines were operating in 2008 and they produced approximately 8 million tonnes in total, of which 98% was produced by 7 large mines and the remainder by 8 smaller mines. One large mine was in care and maintenance. Additionally, 35 operating opencast mines produced approximately 9.5 million tonnes of coal. Imports of coal in 2008 were 43.9 million tonnes, 1.2% higher than in 2007.

3.1.2 Brown Coal 80. World production of brown coal declined by 4 million tonnes to 951 million tonnes in

2008. It has remained broadly stable at 900-1,000 million tonnes a year over the last fifteen years, with limited variation in the regions and countries from which it is produced. The largest producing country was Germany, and other large producers included Australia, the Czech Republic, Poland, Turkey and the USA.

81. Australian brown coal production increased by 11% to 72.4 million tonnes in 2008. Brown coal is predominantly used for power generation in the states where it is produced; i.e. Victoria, South Australia, and Western Australia.

82. In the Czech Republic, the development of new brown coal production capacity is being opposed. Current brown coal production capacity is sufficient to meet demand to 2030, but this could be extended to 2050 if further development was allowed.

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83. There are eleven opencast lignite mines in operation in Germany, with a total production of 175.3 million tonnes (53.8 million tonnes coal equivalent) in 2008, about 2 million tonnes lower than in 2007. Production and investment was relatively stable in the first four months of 2009, with production at the same level as in the first four months of 2007.

84. In the Rhenish basin, RWE Power AG produced 95.8 million tonnes in 2008 from its three opencast mines Hambach, Inden and Garzweiler. E.ON Kraftwerke GmbH’s Schöningen-Süd opencast mine produced 2.1 million tonnes.

85. During 2008, the MIBRAG mines in the Central German basin produced 19 million tonnes (Profen 8.8 million tonnes, Vereinigtes Schleenhain 10.2 million tonnes) an increase of 0.4 million tonnes on 2007. Romonta mined 0.5 million tonnes.

86. The four Lausatian mines of Vattenfall Europe Mining produced in total 57.5 million tonnes, 1.6 million tonnes less than in 2007. Preparations to reopen the fifth mine, Reichwalde, progressed according to schedule. The open cast mine will supply the Boxberg 675 MW unit R, which is due to start operation in spring 2011.

87. Existing state-owned coal production capacity in Turkey is 73.5 million tonnes/year of lignite and 5million tonnes/year of hard coal. Some inactive or inefficient lignite mines have been transferred to the private sector. Lignite production reached 65 million tonnes in 1999, but decreased steadily between the years 2002 and 2004 to reach 43.7 million tonnes as power station demand for the fuel declined. However, production subsequently increased to 55.3 million tonnes in 2005, 61.5 million tonnes in 2006, 72.1 million tonnes in 2007 and 79.1 million tonnes on 2008 (estimated). This increase has been driven by government energy policy favouring domestic lignite based electricity generation and the start of production at two new lignite based power stations, Can 18 Mart and Elbistan B.

3.1.3 Company Developments 88. The financial crisis has impacted the market value of some mining companies, while

creating opportunities for others. For example, during the first half of 2009 the Hong Kong-based trader Noble took control of Gloucester Coal after a three-month takeover battle that brought to an end Whitehaven Coal’s ambitions to merge with Gloucester and Xstrata proposed a $68 billion merger with Anglo American, although the “merger of equals” proposal was rejected by Anglo.

United States of America10

89. Alpha Natural Resources, Inc. and Cliffs Natural Resources Inc. began working on a potential merger in July 2008, but due to the steel market contraction later in the year, the companies abandoned the plan in November 2008. Alpha sold some of its underground coal reserves known as the Kentucky May Property to a private coal producer in October 2008. In May 2009, Alpha announced its intent to acquire Foundation Coal Holdings in an all-stock buy-out that was finalised in July.

90. America West Resources, Inc., a Utah coal operator, announced in December 2008 that its Hidden Splendor Resources, Inc. subsidiary had emerged from Chapter 11 bankruptcy.

91. ArcelorMittal acquired Central Appalachian region mining company Mid Vol Coal Group’s metallurgical coal assets in June 2008. In July, the company agreed to acquire

10 Source: National Mining Association Coal Producer Survey 2009 and others

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the Concept Group mine and reserves adjacent to the Mid Vol Coal Group operations.

92. Arch Coal, Inc. announced an agreement to buy Jacobs Ranch mine assets from Rio Tinto Energy America in March 2009.

93. C.W. Mining Co. was forced into bankruptcy in January 2008.

94. International Coal Group, Inc. (ICG) acquired the former Powell Mountain mining operations in May 2008.

95. James River Coal Co. agreed to purchase some coal reserves and permits from Cheyenne Resources, Inc. in June 2008.

96. Jim Walter Resources, Inc., now Walter Energy Inc., purchased Taft Coal Sales & Associates mines and reserves in September 2008.

97. Massey Energy Co. acquired the Mountaineer #2 Mine and reserves in West Virginia in October 2008. Massey completed the acquisition of various residual coal assets of The Brinks Company in November 2008.

98. Mechel Mining OAO, a leading Russian mining and metals company, announced in April 2009 that it had a definitive agreement with Bluestone Coal Group to acquire Bluestone’s coal production and reserve assets in West Virginia.

99. Metinvest Group, a Ukrainian steel and mining company, acquired Central Appalachian producer United Coal Company in April 2009.

100. Monterey Coal Co., owned by ExxonMobil, sold its Monterey No. 1 underground mine, which had been closed at the end of 2007, to Cline Group affiliate, Macoupin Energy in January 2009. Shortly after, Natural Resource Partners purchased the mine’s coal reserves and related infrastructure assets.

101. Murray Energy Corp. announced in early 2008 that its Galatia Complex in Illinois was for sale.

102. Rio Tinto is continuing its efforts to divest Rio Tinto Energy America, one of the largest coal producers in the USA.

103. Severstal Resources, Russia’s largest steelmaker, acquired Pennsylvania based PBS Coal Corp. in November 2008.

Canada

104. Sherritt International Corporation completed its acquisition of the remaining share in the Royal Utilities Income Fund from the Ontario Teachers’ Pension Plan in June 2008. Sherritt currently supplies domestic utilities and international companies with fuel for electricity generation.

105. Teck Resources Limited (Teck) acquired the remaining 60% interest in the Elk Valley Coal Partnership from Fording Canadian Coal Trust and became the sole owner in October 2008. Teck Coal Limited was created to replace Elk Valley Coal Corporation.

Australia

106. In July 2008, BHP Billiton Mitsubishi Alliance (BMA) announced that they acquired New Saraji metallurgical coal project in Queensland, Australia from New Hope

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Corporation for US$ 2.1bn. The undeveloped resource is located adjacent to BMA’s Saraji mine near Dysart in Queensland’s Bowen Basin.

107. In August 2008, Whitehaven Coal Limited announced that J-Power and EDFT would acquire their 7.5% stakes in the Narrabri Coal Project in the Gunnedah area of New South Wales. Coal production is expected to start in the second half of 2009.

108. In October 2008, Marubeni Coal Pty Ltd announced the increase in its share of Resources Pacific Holdings Limited in New South Wales from 10.24% to 22.22%.

109. Chinese investment company CITIC Group increased to 23.39% its stake in Australian PCI coal producer Macarthur Coal.

110. In June 2009 Gloucester Coal Ltd. which operates the Stratford and Duralie mines in New South Wales was bought out by Noble Group of Hong Kong.

111. In May 2009 Waratah Coal signed a memorandum with China Metallurgical Coal of China (MCC) concerning its Galilee Project. The memorandum allows MCC rights on 30 million tonnes of thermal coal per year in return for obtaining funding for 70% of the project development costs. The Galilee project is a proposed A$7 billion export thermal coal project in the as yet unexploited Galilee basin 450km west of Rockhampton.

112. In August 2009 the Hong Kong listed Yanzhou Coal Mining made a successful (subject to shareholder approval) offer for Australian coal company Felix Resources. The takeover was subsequently approved by the Australian Government after Yanzhou committed to list its Australian operations in Australia and reduce its ownership of the same assets to 70% by 2012. Felix’s operations include the Ashton, Minerva and Yarrabee mines as well as the Moolarben project.

South Africa

113. ArcelorMittal South Africa bought a 16.3% stake in mining company Coal of Africa to secure part of its future coal needs.

114. Although the number of Historically Disadvantaged South African (HDSA) mines has increased, their contribution in terms of total production is still relatively small. However, with the establishment of the bigger HDSA mines, involving companies such as Exxaro, Optimum Coal Holdings, Siyanda, Shanduka, African Rainbow Minerals and others, a greater shift to HDSA ownership has occurred.

Germany

115. CEZ (via its lignite mining arm Severoceske Doly a.s., SD) will acquire the German Mining group, MIBRAG, with J&T group in a 50/50 joint venture. MIBRAG has two large opencast lignite mines in Germany with 19 million tonnes of annual production and three CHP plants.

Turkey

116. At the beginning of 2009, Turkish Coal Enterprises (TKI) had 151 deposits, of which 14 active, 11 leased and 14 inactive mines have operating licenses. The policy of leasing inactive mine deposits to the private sector, or transferring the licenses back to the government office if not successfully tendered, continues.

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3.2 Coal Consumption 117. According to the BP Statistical Review of World Energy, June 200911

118. For the United States of America, the US Energy Information Administration EIA) estimates total (i.e. hard coal and brown coal) coal demand for use in the United States of America was a record 1.122 billion tons in 2008 (1.017 billion tonnes). This is the third highest level of coal use in history, 0.6% below the records set in 2007 due to a combination of milder weather in late winter and summer and an economy that declined into recession during the last half of the year. Exports were 81.5 million short tons (73.9 million tonnes) in 2008, bringing total demand for USA coals (not considering inventory changes) to a record 1.203 billion short tons (1.091 billion tonnes).

, annual coal consumption grew by 3.1% in 2008, more quickly than oil (marginal decline) or gas (+2.5%). The strong growth in coal consumption is fuelled by China, where consumption rose 6.8% over the previous year.

119. According to BP statistics, total consumption of coal in Russia in 2008 increased by 8.4% to 101 million tonnes oil equivalent (approximately 216.4 million tonnes of coal). This figure is lower than the total production of coal in Russia in 2008 (326.5 million tonnes), indicating the extent of net exports. Coal imports into Russia come mainly from CIS countries (Former Soviet Union).

3.2.1 Total Hard Coal Consumption 120. During 2008, IEA provisional data show that World consumption of hard coal grew by

400 million tonnes, over 7%. Although the IEA’s previous estimate of nearly 7% growth in 2007 has now been revised to 4.8%, the figures continue to give a strong indication of substantial growth in hard coal consumption every year in the recent past. World hard coal consumption has now increased by a total of 57% in the eight years since 2000.

112008 growth rates have been adjusted to remove the leap year effect

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0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

1970

1980

1990

2000

2008

e

Chart 2 - Hard Coal Consumption(million tonnes)

Source: IEA Statistics

EU(19) OECD World

© OECD/IEA, 2009

121. Both Chart 2, above, and Table 2, which shows hard coal consumption figures for the last three years, illustrate significant decline in EU19 and OECD countries in contrast to the substantial growth originating in the developing economies.

Table 2 - Hard Coal Consumption (million tonnes) 2006 2007 2008e

m.tonnes m.tonnes change m.tonnes changeEU(19) 356 358 0.5% 331 -7.7%OECD 1701 1735 2.0% 1704 -1.8%World 5168 5415 4.8% 5814 7.4%

© OECD/IEA, 2009 122. The world financial crisis and economic downturn appear to have disproportionately

affected OECD countries, where hard coal consumption declined by 1.8% in 2008. China was yet again largely responsible for the majority (305 million tonnes, or over 75%) of the increase in world hard coal consumption during 2008, with India accounting for a further 48 million tonnes, or 12%, of the growth. These countries experienced growth in hard coal consumption of about 12% and 10% respectively in 2008.

123. Japan has few indigenous coal resources, although it has a high demand for coal. As a consequence nearly 100% of its coal requirements are satisfied by imports. Japan is one of the largest importers of coal in the world. Total metallurgical coal, thermal coal and anthracite imports in FY2008 were 185.6 million tonnes, a reduction of about 1.7 million tonnes on the previous year. The largest providers were Australia (61%), Indonesia (19%) and China (7%).

124. About 40% of coal consumed in New Zealand is used for power generation. New Zealand has only one coal-fired power station, which is the 1000 MW Huntly Power Station in the North Island. The use of this power station had been scaled back in 2007 in favour of gas, although the plant was brought into use again by a particularly dry winter in 2008 which impacted on hydroelectricity production. Other major coal consumers are dairy processor Fonterra and New Zealand Steel.

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125. For the year ended September 2008, New Zealand's net electricity generation was 42,705 GWh. About 50% of New Zealand's electricity is produced from hydro, 25% from gas and 10.1% from coal.

126. Of South Africa’s 252 million tonnes production in 2008, Eskom consumption accounted for 48% (121Mt) for power generation, and Sasol 18% (45Mt). Local market consumption is approximately 73% of the total output. Coal exports are mainly through the Richards Bay Coal Terminal (63Mt), with significantly smaller volumes through Durban (1.2%) and Maputo (1.0%).

127. Since 2004, coal consumption at Sasol’s Sasolburg plant has reduced from 6.8 million tonnes to 1.7 million tonnes in 2008 as the plant has progressively changed its feedstock from coal to Mozambique gas. Sasol’s coal production is now closely aligned with the steady 40 million tonnes/year consumption of its Secunda coal-to-liquids plant.

128. In Germany, the hard coal consumption decreased by about 7% from 67 million tonnes coal equivalent to 62 million tonnes coal equivalent in 2008, including thermal coal imports of approximately 44 million tonnes and metallurgical coal imports of 4 million tonnes. The majority of imported coal is used in power plants (70.7%). The iron and steel industry used 26.7% of total coal imports in 2008 and the heating market only 2.6%. The average German border price for imports was nearly €112/tonne hard coal equivalent in 2008, far higher than the average of €68 / tonne hard coal equivalent in 2007.

129. In the United Kingdom, demand for coal in 2008 was 58.2 million tonnes, 7.4% lower than in 2007. However, this trend was reversed on Q1 2009. Coal consumption in the three months to March 2009 was 17.4 million tonnes, 5.6% higher than in the same period a year earlier, while imports grew by 13% to 12.5 million tonnes over the same period.

130. According to SUEK calculations based on ROSSTAT and Federal Customs Service data, total hard coal consumption in Russia rose by 7.2% in 2008 to 179 million tonnes. The IEA estimates a 20.8% increase to 172 million tonnes, indicating major differences in hard coal consumption data for 2007 and/or 2008.

131. In France, since hard coal mining ceased in 2004, all coal consumption is based on imported coal. Electricity generators and the steel industry are exempted from the coal tax, introduced from 1st July 2007 onwards in compliance with the European Directive on energy taxation. Total coal consumption fell over 6% to 19.6 million tonnes, a historical low, due largely to reduced electricity (-8.5%) and iron and steel industry (-6%) demand with a small reduction in general industrial demand. Coal accounted for 4% of the fuel used for electricity generation, while nuclear accounted for 76% and hydro 12%.

132. In 2008, France imported 22.8 million tonnes of coal, a 13% increase on 2007, with two thirds sourced from Australia, the United States of America, South Africa and Colombia. Imports from the USA (4 million tonnes) and Russia (1.8 million tonnes) both more than doubled.

133. Turkey’s hard coal consumption in 2007 was 25.2 million tonnes. Of this, 23 million tonnes was imported and the major supplying countries were Russia and Ukraine, China, South Africa, Canada, the USA and Australia.

3.2.2 Thermal Coal Consumption 134. World thermal coal consumption increased by 7% (329 million tonnes) in 2008 according

to IEA provisional estimates, mirroring the increase in overall hard coal consumption.

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World thermal coal consumption has increased by 59% since the year 2000. Recent growth has been driven by very rapid growth in developing economies including China (12%, building on 2007 growth of 6%) and India (over 8% growth in both 2007 and 2008). Growth in thermal coal consumed by non-OECD countries in aggregate was over 11% in 2008, compared with a decline in OECD countries of approaching 2%.

Table 3 - Thermal Coal Consumption (million tonnes) 2006 2007 2008e


© OECD/IEA, 2009

135. In the United States of America, Energy Information Administration (EIA) estimates show that the electric power sector (this includes electricity generators and independent power producers but not commercial or industrial electricity generators) used 1.043 billion short tons (946 million tonnes) of thermal coal in 2008 for electricity generation. This was a drop of just over 3 million tons (0.3%) from 2007 levels - very minor considering the decline in economic activity which was accompanied by a 1% drop in total electricity generation year on year. The first and second halves of the year were markedly different however, with electricity generation increasing by 1% in the first half and declining by nearly 3% in the second half. Coal-fired electricity generation accounted for close to 50% of electricity produced in 2008, unchanged from 2007. Natural gas accounted for 20.1%, nuclear for 20.4% (where generation was nearly the same as in 2007) and renewable energy (except hydro) for 2.3%. Conventional hydro-electric production was up slightly due to higher rainfall than last year in the North West.

136. According to the EIA, 1,131 MW of new coal fired capacity came on line in 2008, including the Cross plant in South Carolina, the Pleasant Prairie plant in Wisconsin, the TS Power Plant in Nevada and the Wygen II plant in Wyoming. As in most recent years the preponderance of new capacity in 2008 was fired by natural gas (9.8 GW).

137. At the beginning of October, the EIA had published electric utility data through to June 2009. That preliminary data showed that in the first six months of 2009, generation in the electric power sector was 4.9% lower than in the first six months of 2008. Coal absorbed the entire decline in generation as coal-fired generation was down by 12.8%, the largest decline of any sector. Coal's share of the market for the first six months was 46.2%. Natural gas and nuclear generation both increased year to date through to June. Coal consumption in the electricity generating sector was down 11% for the first six months of 2009. Electrical production in the traditional coal burning areas has been especially hard hit by the sharp decline in activity in manufacturing and other economic activity. An abnormally cool summer has also contributed to the decline in electric production and coal use. Finally, lower natural gas prices negatively affected utility coal demand.

138. Coal use by electricity generators is forecast to decline by 9.1% for the whole year 2009 according to the latest short term forecast published by the EIA (September 2009). The EIA predicts that generators will use 946 million short tons (858 million tonnes) to account for 47.7% of electricity produced, indicating that the market for coal will not improve in the second half of the year even if there is an improvement in the economy. Total generation is expected to be 3.2% lower in 2009 when compared with total year 2008.

139. Low coal inventories have not been an issue for at least three years and will certainly not be a problem in 2009, when inventories will end the year at or near to record levels. According to the EIA, coal inventories at all consumers’ sites stood at 206 million short tons (187 million tonnes) at the beginning of July 2009 - 34 million tons higher than at the

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end of 2008. Inventories including those held by producers were 237.5 million short tons (215 million tonnes). As far as utilities are concerned, the 198 million tons on hand at the beginning of July represented the highest inventory level history. The private company Genscape has estimated that, as of 12 October, stockpiles at utilities stood at levels 53% higher than the 10 year average and 22% above year earlier levels. These levels are equivalent to 69 days supply, 43% above the 10-year October average of 48.3 days. This situation is unlikely to change over the rest of 2009.

140. Industrial, commercial and retail use of coal for generation of thermal and for other purposes was 57.7 million short tons (52.3 million tonnes) in 2008, 3.3% below 2007 levels. Again. This was due to the economic recession and the EIA expects that industrial coal use will decline significantly (by 10 million short tons) in 2009.

141. In 2008, Japan imported around 105.1 million tonnes of thermal coal, an increase of 4.1 million tonnes on the previous year. Australia remained as the largest thermal coal supplier with a 68% share. Indonesia, the biggest thermal coal exporter in the world, was the second-largest exporter to Japan with a 16% share. China, on the other hand, reduced its share from 11% to 8% because of its coal export restrictions due to its growing domestic demand.

142. In Germany, consumption of electricity produced from coal in 2008 was 278 TWh (45% of the total 616 TWh gross consumption), less than the previous year. Coal burn at power stations fell by 7%. The primary sources of thermal coal imports for power plants were South Africa (9.1 million tonnes), Russia (6.9 million tonnes), Colombia (5.7 million tonnes), Poland (3.8 million tonnes) and the USA (3.1 million tonnes).

143. In the UK, coal currently accounts for 37% (29GW) of electricity capacity, generating 31% of the UK’s electricity in 2008. Coal consumption by electricity generators was 47.8 million tonnes, 9% lower than in 2007. However, consumption during the first three months of 2009 was 15.2 million tonnes, a 10% increase on the same period in 2008.

144. Around 25% of all the UK's existing generation capacity is scheduled to close inside the next decade through a combination of fossil plants opted out under the EU's Large Combustion Plant Directive and nuclear plants at the end of their life. All of the coal-fired plant uses bituminous coal, either indigenous or sourced from the world market.

145. The Russian government has adopted a road map for the development of new electricity generation capacity to 2020. Coal-fired power plant capacity as a share of total thermal power plant capacity will increase from 27.4% to 30.1% by 2020, and its share of power production will increase from 25.1% to 32.5%. According to another document “Energy Strategy of Russian Federation to 2030” the share of gas in primary energy resources utilization by power plants will decrease from 50% to 35% by 2030, because natural gas commands a much higher price in export markets than in the domestic market.

146. In 2008, Gazprom and SUEK entered into a Strategic Partnership Agreement stipulating coordination of the companies' actions in the power industry. The Agreement identifies the direction of long-term cooperation between the companies, including upgrading and construction of new modern coal-fired power generating capacity, joint investments in coal-fired generation, gas substitution and increased coal consumption at power plants, development of innovative projects in coal fired generation and a range of other joint projects.

147. The economic downturn has affected thermal coal demand in Russia. In the first half of 2009, compared with the first half of 2008, electricity production by Russian fossil fuels-based power plants fell by 6.2%, while heat supplied by Russian power plants and boiler stations came down only 0,5%.

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3.2.3 Metallurgical Coal Consumption 148. Table 4 shows IEA statistics for metallurgical coal demand in the major world regions.

Table 4 - Metallurgical Coal Consumption (million tonnes) 2006 2007 2008e


© OECD/IEA, 2009

149. Trends in World consumption of metallurgical coal were similar, but slightly more pronounced than those in thermal coal. World consumption increased by nearly 760 million tonnes, or over 9%, in 2008. Consumption in China increased by 52 million tonnes (over 13%) to account for almost 75% of the world growth. while India accounted for 15%, with growth of 10 million tonnes, 22% up on 2007. Strong growth was also seen in Russia (+3 million tonnes, 6.7%) and Brazil (+1.3 million tonnes, 12%). Major reductions were seen in Australia, Germany and the USA, contributing to the overall decline experienced in OECD countries.

150. World blast furnace iron (BFI) and crude steel (CS) production declined by 2.3% and 1.6% respectively in 2008 and this trend accelerated in 2009, particularly with respect to crude steel production (-3.2% BFI, -8.4% CS). China demonstrated a startling exception to this trend (+15.7% BFI, +13.6% CS). In 2009, China produced 60% of the world’s blast furnace iron and 47% of its crude steel.

Table 5 - Primary Iron & Steel Production Blast Furnace Iron (m. tonnes) Crude Steel (m. tonnes)

2008 2009 change 2008 2009 changeEU (19) total 105 71 -31.8% 173 121 -30.2%OECD 283 207 -26.9% 507 371 -26.8%World 923 894 -3.2% 1304 1194 -8.4%

Source: World Steel Association (worldsteel) 151. Metallurgical coal use in the United States of America declined by 700,000 short tons

(635 million tonnes) in 2008 to 22 million short tons (20 million tonnes), a decline of 2.8%. Steel production in 2008 was 100.7 million tons, 6.9% lower than the 108.1 million tons produced in 2007. The industry operated at an average 80.9% of capacity in 2008, but at the end of the year was operating at only 41% capacity. Steel production in blast furnaces was 42% of the total, slightly higher than the 41% in 2007. Steel production through to the end of August was 36.5 million tons, 49% below the same period of 2008. Clearly the effects of lower automotive production and lower manufacturing and economic activity are being felt by the entire steel industry. The US “cash for clunkers” programme may add slightly to demand during the last part of 2009, but total year production will still be well below 2008 levels.

152. This has carried over to the coal industry, where use of metallurgical coal for coking totalled only 7.8 million tons (7.1 million tonnes) in January-June 2009, 30% below the same period in 2008. The EIA expects use of coal for coking purposes to be 15.5 million tons (14.1 million tonnes) in 2009, 30% below 2008.

153. Japanese Steel Mills’ crude steel production in CY2008 was 119 million tonnes, a slight (1 million tonnes) decrease on CY2007. The tonnage of metallurgical coal (coking coal and PCI coal) imported in CY2008 was 81 million tonnes, a slight (1 million tonnes)

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increase on CY2007. In CY2009, metallurgical coal demand is expected to decrease as steel production decreases. In the seven months to July 2009, compared to the same period in 2008, Japanese iron production was 33% lower and steel production 38% lower. These reductions are in line with the general trends shown in the World Steel Association figures.

154. In Germany, metallurgical coal consumption declined by 12% to 20.2 million tonnes in 2008, while imports were stable at nearly 10.3 million tonnes. The primary sources of imported metallurgical coal were Australia, the USA and Canada.

155. In the United Kingdom, the use of coal in coke ovens and blast furnaces declined by 1.8% to 7 million tonnes in 2008, with a further massive reduction of over 25% to 1.3 million tonnes during the January-March period in 2009, compared to the same period in 2008.

156. In Russia, according to ROSSTAT, the volume of metal mining production decreased by 5.5% in the first half of 2009 compared to the same period of the previous year; and production of basic metals and fabricated metal products lost 26% over the same period. According to Federal Customs Service statistics the physical volume of coke and semi-coke exports from Russia in January-May 2009 fell by 38% compared to the same period of the previous year and the physical volume of ferrous metals and iron ore export sank by 25%.

3.2.4 Brown Coal Consumption

Table 6 - Brown Coal Consumption (million tonnes)

2006 2007 2008em.tonnes m.tonnes change m.tonnes change

EU(19) 380 382 0.5% 367 -3.9%OECD 621 630 1.5% 625 -0.8%World 943 960 1.8% 953 -0.7%

© OECD/IEA, 2009 157. World consumption of brown coal decreased slightly in 2008 to 953 million tonnes,

although the pattern was not consistent between countries. Australia (+6.7 million tonnes, 10%), Canada (+5.2 million tonnes, 14%), Russia (+5.5 million tonnes, 8%) and Korea (+2.5 million tonnes, 38%) significantly increased consumption while reductions were seen in Germany (-5.3 million tonnes, -3%), Spain (-7.25 million tonnes, -75%) and Indonesia (-4.0 million tonnes, -13%).

158. For the United States of America, brown coal (lignite) use was approximately 74.3 million tons (67.4 million tonnes). All lignite produced in the United States of America is used for power generation.

159. In Germany, according to AG Energiebilanzen, lignite use fell by 3.6% to 53.0 million tonnes hard coal equivalent in 2008, in contrast to an overall increase of 1.1% in primary energy consumption in the country.

160. According to DEBRIV, the gross capacity of lignite fired power stations in Germany is around 22GW and RWE has stated that Germany produced 150 TWh of electricity (gross generation) from lignite in 2008, of which 76 TWh was generated by the company. The share of lignite in Germany’s total gross power generation (2008: 639 TWh) was 23.5 %.

161. In Turkey, lignite is consumed in three sectors: thermal power stations, industry and

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households, but power generation is the main consumer. While the share of lignite in electricity generation reached its highest value of 47% in 1986, this had declined to 15% by 2004 due to an increase in the use of natural gas in electricity generation. However, over the last four years it has increased again to 21.1% in line with government energy policy and the commissioning of new lignite-fired power stations at Can 18 Mart and Elbistan B.

3.2.5 Company Developments 162. The reform of Russian power utilities (the Russian power monopoly RAO UES) was

completed in July 2008. RAO UES was replaced by many power utility companies, including 6 wholesale generating companies (OGKs) and 14 territorial generating companies (TGKs), most of which were privatized. Alone amongst the coal industry, SUEK decided to invest in coal-based generating companies, purchasing majority interests in TGK-12, TGK-13 and the Far East Generating Company. This was in line with the company’s fundamental goal of achieving synergy through the integration of coal mining and power supply businesses.

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3.3 Trade and Prices 3.3.1 Freight Market 163. Chart 4 illustrates the trends of monthly average Capesize freight rates for four routes

representative of thermal coal (Richards Bay, South Africa) and metallurgical coal (Gladstone, NWS, Australia) imports to the Atlantic (Rotterdam) and Pacific (Japan) basins.

164. In terms of the longer term trend, contrasting with a period of relative stability at about US$10/tonne seen in the late 1990s, 2003 saw the start of a period of higher rates and market volatility. Following peaks at the beginning of 2004 and again at the beginning of 2005, steady growth in rates from mid 2006 culminated in rates peaking again in November 2007, at almost double the rates seen during the previous peaks.

165. 2008 was marked by extreme volatility in Capesize freight rates, which achieved both their highest and lowest historical levels during the year. While the beginning of 2008 was marked by a return to lower levels, absolute record highs, boosted again by the expansion of world trade mainly driven by China, were seen in May and June 2008. The sharp increase in seaborne trade of iron ore, mainly to China as a result of expanding steel production, and increased coal demand for electricity generation and steel production in Asia resulted in the high rates observed in the first half of 2008. Although demand on the Atlantic Basin remained flat, freight rates on this basin were influenced by the high levels observed on the Pacific basin, as some Asian buyers started to buy coal from traditional Atlantic suppliers. Rates on the Richards Bay/Rotterdam route reached $62/tonne on 5 June 2008.

166. The effects of the world financial crisis and the resulting slump in economic growth prospects started to hit the freight market in September 2008 and rates had slumped to historically low levels by the end of the year. The economic downturn had a severe impact on the iron and steel industry, reducing imports of iron ore and metallurgical coal everywhere but China. The impact was less pronounced for thermal coal.

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167. Since the beginning of 2009, a slight recovery has been observed, although rates remain highly volatile. They remained very low in the first four months of 2009 - below $10/t for the Richards Bay/Rotterdam route. From May 2009 they started to climb again, driven by increasing iron ore and coal imports into China, and settled at $18-20/tonne in June-July 2009. The second half of 2009 was again marked by high volatility, with lows of $11/tonne in September and highs of $21/tonne in November. In 2009, China more than doubled its coal imports to 127 million tonnes. Its iron ore imports also grew in line with increasing steel production. China imported 628 million tonnes of iron ore in 2009, up 41.6% compared with 2008. The financial stimulus adopted by the Chinese Government in February 2009 largely explains these growth rates.

168. On the demand side, maritime dry bulk trade for the first time ever dropped in 2009 and totalled an estimated flow of 2,980 million tonnes, a decrease of 3% on the 2008 figure of 3,062 million tonnes. Maritime dry bulk trades in coal, iron ore, grains, bauxite, phosphate, sugar, fertilizers, scrap and steel all contribute to the demand for bulk seaborne trade. The steel industry was badly hit by the financial and economic crisis everywhere except China; and led to a sharp decline in iron ore and metallurgical coal imports which was particularly strong in OECD countries. The same applied to thermal coal imports, as electricity demand decreased in line with lower economic activity.

169. The sharp increase in seaborne trade volume of iron ore to China together with its increasing thermal coal imports, particularly in the second half of 2009, allowed the recovery in freight rates observed in 2009.

170. On the supply side, the bulk carrier fleet has been growing rapidly since 2003. The number of Capesize (deadweight in excess of 100,000 tonnes) and Panamax (deadweight about 60,000 to 100,000 tonnes) reached 2649 vessels in early 2010 (309 million deadweight tonnes), an increase of 70% in available tonnage since 2003.

171. Orders for new vessels to be delivered in 2010-2013 represent 66% (Capesize), 175% (small Capesize) and about 33% (Panamax) of the existing fleet size. The effect of the financial and economic crisis on new vessel orders has not been as great as expected. Only 10% of new orders were cancelled in 2009, compared to expectations at the beginning of 2009 of 25% cancellations during the year. Neither did vessel scrapping play a big role: bulk carrier scrapping peaked at 6.5 million deadweight tonnes in Q1 2009 but then fell back quickly, with only one Capesize vessel demolished in Q4 2009.

172. The trend was to delay rather than cancel orders. By the end of 2009, 125 ships in the order book for that year had not yet been delivered, 111 of which were expected to be delivered in 2010. Port congestion had a bigger impact on fleet availability in 2009. Recurrent congestion in Australia, Brazil and China limited available shipping hold capacity by an estimated 5 to 7% in 2009.

173. In summary, shipping rates in 2009 were maintained at higher levels than were originally anticipated but future rates remain uncertain; and will be influenced by factors including delivery of vessels delayed from 2009, new vessel orders, future port congestion, the level of Chinese raw material imports and the extent of more general economic recovery.

3.3.2 Trade Volume 174. Global demand for seaborne traded thermal coal did not grow in 2008, according to

IEA statistics, the first year that this has happened since 1993. Over the last 10 years, it has still grown by an average of over 30 million tonnes a year and has more than doubled over that short period.

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175. Global demand for seaborne traded metallurgical coal, on the other hand, grew by 18 million tonnes (nearly 8%) to 243 million tonnes during 2008. Over the last 10 years, seaborne metallurgical coal trade has increased by over 40%.

176. Although there differences between the IEA figures for seaborne hard coal trade figures and those published by the German Coal Importers Association, the overall view of seaborne hard coal trade in 2008 is similar. The latter organisation shows strong seaborne export growth out of Indonesia (+13 million tonnes to 202 million tonnes), Australia (+11 million tonnes to 261 million tonnes) and USA (+16 million tonnes to 53 million tonnes). Exports decreased from China (-7 million tonnes to 46 million tonnes), South Africa (-5 million tonnes to 63 million tonnes) and Poland (-3 million tonnes to 2 million tonnes).

177. The following table shows United States of America coal exports in 2007, 2008 and for the first eight months of 2009:

Table 7 – USA Coal Exports (million short tons12

)

2007 2008 Jan-Aug 2008

Jan-Aug 2009

change ‘09/’08

to Canada Metallurgical 3.731 3.671 1.801 1.314 -27.0% Thermal 14.593 19.095 12.375 5.635 -54.5% TOTAL 18.324 22.766 14.176 6.949 -51.0%

to Overseas Metallurgical 28.548 38.948 25.687 20.374 -20.7% Thermal 11.775 19.674 10.314 8.288 -19.6% TOTAL 40.323 58.622 36.001 28.662 -20.4% Total Exports 58.648 81.388 50.179 35.610 -29.0%

Source: US Department of Commerce

178. Clearly exports in 2008 were much better than they will be in 2009. Exports in 2008, just over 81 million tons, represented a 38% increase over the 2007 level of 58.6 million tons and were at their highest level in over a decade. US Coal benefited from the global rush for resources and also from the fact that the US dollar was trading lower against most international currencies for much of the year.

179. Mine, transportation and infrastructure constraints in Australia together with high domestic demand from China, South Africa, Indonesia and Russia constrained the world market and continued to fuel interest in US coal by international purchasers throughout much of 2008. Record high oil prices in the first half of the year added to demand levels. Suspension of coal exports from China and limitation of exports by South Africa helped US suppliers.

180. On the metallurgical side, Brazil was the largest single country customer for US coal taking over 6 million tons. Europe remained the largest overall customer for US coals, accounting for 60% of the total increase in metallurgical coal shipments. The largest European customers continue to be The Netherlands, Italy, France and the United Kingdom, with Poland and Romania not far behind. In 2008 shipments to Asia and Africa were nearly double 2007 levels, with the largest customers being Turkey, India, Egypt and Japan.

181. Thermal coal exports (excluding lignite and anthracite) increased by 45% for the second

12 Multiply by 0.9072 for metric tonnes

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consecutive year. Canada was the largest customer for US thermal coal, taking 19 million tons or exactly half of the total thermal coal shipped from the US. Thermal coal exports to all other regions increased, with the greatest share going to Europe (the United Kingdom, Netherlands, France and Germany.

182. As Table 7 shows, in 2009 the demand for US export coal from all regions and countries declined dramatically due to the world wide economic recession. By the end of August there was a glimmer of recovery in the metallurgical coal market, but the markets are far from normal and are not expected to return to more normal levels of trading for at least two years. The EIA is forecasting a total US export level of 57.3 million short tons in 2009, a level that may be difficult to meet.

183. Imports of coal into the Unites States of America declined from 36.3 million tons in 2007 to 34.3 million tons in 2008. The majority of the coal imported by US utilities originates in Columbia, with Indonesia coming in a distant second and Venezuela third. Coal imports are expected to decline in 2009 to 24 million tons according to EIA forecasts. Imports were 15.3 million tons in the January-August 2009 period, 31% below the first eight months of 2008. All major countries shipping coal to the USA experienced a decline, with Columbia experiencing the greatest decline and absorbing 70% of the total USA market decline.

184. Canada exported approximately 32 million tonnes of coal in 2008, accounting for 47% of its coal output during the year. Almost all of the metallurgical coal produced in western Canada is destined for offshore markets. In 2008, Canada exported about 26.5 million tonnes of metallurgical coal (similar to the 2007 volume) and about 5.7 million tonnes of thermal coal (4 million tonnes in 2007). The largest increase in thermal coal exports was to South Korea, whose export volume doubled to 2 million tonnes in 2008. Thermal coal exports to Brazil and China also increased by 500,000 tonnes each. About 80% of Canada’s seaborne coal exports were shipped through coal terminals in Vancouver, while the rest was shipped through the Ridley Terminals in Prince Rupert in northern B.C.

185. Canada imported 20.6 million tonnes of coal in 2008 (17.4 million tonnes of thermal coal for power generation and 3.3 million tonnes of metallurgical coal), 2.4 million tonnes less than in 2006. The United States of America supplied 17.9 million tonnes and the combined supply from Colombia, Venezuela, Russia and Ukraine was 2.7 million tonnes.

186. Australian exports like those of other exporters have been impacted by global economic conditions, with exports for the first half of 2009 increasing by only 1% compared to the same period in 2008. Metallurgical coal exports declined 9% over the period as steel producers slashed output across the globe, while thermal exports actually increased by 13% with a massive increase in demand for imported coal from China and to a lesser extent Korea, masking a decline in demand from most other thermal coal importing countries.

187. Exports from South Africa declined from 66.3 million tonnes in 2007 to 61.9 million tonnes in 2008. In 2009 South Africa’s export capacity remains constrained by rail infrastructure and exports are unlikely to increase. Destinations for South African exports have changed dramatically with demand increasing from India and Pakistan, as well as other Asian countries, displacing traditional markets in Europe where demand for South Africa’s predominantly thermal coal exports has declined as a result of the economic slowdown and low gas prices.

188. German reliance on imported coal continued, with 2008 imports equalling the 2007 figure (48 million tonnes) and supplying over 70% of the country’s total hard coal requirements.

189. Imports of hard coal into Russia, according to Federal Customs Service of Russian

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Federation statistics, grew by 32.1% to 30.9 million tonnes in 2008, including 29.9 million tonnes of hard coal imported from CIS countries. The export volume of hard coal decreased by 0.6% to 97.4 million tonnes in 2008, of which only 14.2% (13.9 million tonnes of hard coal) was exported to CIS countries. In total, the net export of hard coal in 2008 dropped 10.8% to 66.5 million tonnes.

3.3.3 Market Prices 190. World thermal coal trade has developed rapidly over the last 25 years and market

transparency has increased with the introduction of electronic trading systems and price indices. There seems little sign of this growth abating.

191. Although investments in supply and transport infrastructure are being made, the continuing rapid increases in coal demand from countries such as China in the last few years have inevitably put upward pressure on prices and have increased market price volatility.

20

40

60

80

100

120

140

160

180

200

220

2003 2004 2005 2006 2007 2008 2009 2010

$US/

tonn

e

Chart 4 - MCIS Steam Coal Marker PricesSource: The McCloskey Group (www.mccloskeycoal.com)

NW Europe

Asia

192. Prior to 2007, international thermal coal prices had peaked in the second half of 2004 with the ARA CIF delivered price reaching about US$79/tonne. Prices delivered to European distribution ports were on a declining trend during 2005 and the ARA CIF delivered price was down to $51/tonne by the end of the year, with Asian market prices apparently following the Atlantic market. However, prices increased steadily throughout 2006 and 2007, with rapid increases in Asian market prices from March 2007 leading the way and illustrating the effect that Chinese demand for coal, other commodities and shipping continues to have on world markets. In the second half of 2007 and into 2008, European spot prices again led the rapid increase in prices, driven by demand in that region and influenced by continuing infrastructure constraints affecting Australian exports. NW European prices peaked at US$210/tonne in July 2008, with Asian prices reaching US$179/tonne.

193. By December 2008 however, Asian prices had followed European prices in their rapid fall to just over US$80/tonne, levels not seen since mid-2007, and by April 2009 both European and Asian prices had drifted lower to US$66-67/tonne. Since then, there has been a slow but steady increase, with Asian prices reaching over US$90/tonne by January 2010 and European prices following this trend, which appears to have been driven by China. As well as having increased domestic coal production capacity

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significantly to nearly 3 billion tonnes/year, China imported nearly four times more thermal coal in 2009 (nearly 60 million tonnes) than it did in 2008.

194. In the United States of America, limited information is available on spot prices for selected coal types in Central Appalachia, Northern Appalachia, the Illinois Basin, Power River Basin and the Colorado Uinta Basin. The information is prepared by “Platts Coal Outlook” and is published weekly by the US Energy Information Administration on its web site13 (http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html#spot)

195. In general, US Appalachian coal prices have followed the pattern of internationally traded thermal coal prices while Powder River Basin prices have shown no discernable pattern of change and seem to have remained unaffected by international market price movements.

.

196. Most of Canada’s metallurgical coal was traded on an annual contract basis, with 2008 coal year contract prices settled at US$300/tonne in early 2008 as the global price hit record highs. However, the average achieved price was CAN$210/tonne f.o.b. for the 2008 calendar year based on the Canadian customs recorded export prices. It is reported that Canadian producers have settled their 2009 coal year contract prices at US$116-$129/tonne.

197. For thermal coal, preliminary customs recorded price data indicate that the average export price (all coal types) was C$95/tonne in 2008.

198. Canada imports both metallurgical and thermal coal into Ontario, Nova Scotia, and New Brunswick. Most metallurgical coal was imported into Ontario at an average price of C$107/tonne in 2008. Thermal coal was imported into Ontario, Nova Scotia, and New Brunswick at an average price of C$57/tonne in 2008.

199. The term price of metallurgical coal for Japanese Steel Mills in FY2008 increased from the FY2007 term price, reflecting the sharp rise in spot prices due to bad weather in Queensland at the beginning of 2008. The term price of hard metallurgical coal for FY2008 was settled at US$240-300/ t FOBT, about three times higher than the FY2007 price.

200. The term price of thermal coal for Japanese Power Utilities (JPUs) in FY 2008 was settled at around US$125/ t FOBT with Australian coal shippers. (FY2007 term price was around US$55.5/ t FOBT). Historically, this is the highest price settlement ever and was influenced by the previously settled metallurgical coal price and strong demand from China resulting from the Beijing Olympic Games preparations. JPUs subsequently settled the term price of Indonesian high grade thermal coal at a similar level.

201. Domestic producer prices for metallurgical coal in Russia rose by 46.7% to US$45.2/tonne, and thermal coal by 34.9% to US$30/tonne, in 2008. The downturn in coal demand downturn and the 25% depreciation of the Russian ruble subsequently caused average domestic metallurgical coal prices to drop by 40.7% to US$26.8/tonne, and thermal coal prices by 39.1% to US$18.3/tonne, in the first half of 2009.

202. Russian domestic coal prices are lower than world prices for coal. Russia is, by far, the largest country in the world and internal rail transport distances are very large, particularly for export coal. Railway charges form a significant proportion of delivered coal costs and are still set by government. In 2008 the price index for railroad freight transportation increased by 41%.

13 We do not have permission to reproduce that information in this report.

http://www.eia.doe.gov/cneaf/coal/page/coalnews/coalmar.html#spot�

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4 ISSUES RELATED TO COAL 4.1 CIAB Plenary Meeting Discussion 203. The CIAB Plenary Meeting held in November 2009 involved CIAB Members, senior

representatives of the IEA, and others. It included presentations and discussions covering three major policy areas:

• Greenhouse Gas Mitigation Measures – Implications for the Coal Industry in Developed and Developing Economies;

• Energy Sector Investment and the Coal Industry – Implications for Energy Security; and

• Carbon Pricing – Implications for Coal and the Migration of Industrial Activity.

A note of these discussions is available on the CIAB website at (http://www.iea.org/ciab/papers/CIAB_Plenary_Discussion_Nov09.pdf).

4.1.1 Emerging Themes 204. Following the discussions Mr. Wicks, CIAB Chairman, identified the following emerging

themes.

205. IEA World Energy Outlook 2009 – The scenarios had illustrated that “business-as-usual” is unsustainable. He recognised that the 450 Scenario is a projection of a possible outcome designed to promote discussion, but said that its achievement would be very challenging and would incur costs much larger than suggested by previous IEA projections – a particular issue in the current financial climate. The discussion had highlighted the extent of the greenhouse gas emissions reduction challenge, made the point that there is no “silver bullet” solution to the issue, and raised the uncomfortable possibility of an actual outcome lying somewhere between the two scenarios. The view had emerged that COP15 in Copenhagen is not an end in itself but a stage in a journey and that a greenhouse gas emissions reduction agreement is still possible by 2012.

206. Fuel mix, energy security and unintended consequences – The discussion had highlighted the difficulties associated with seeking to reconcile energy supply security and greenhouse gas emission reductions, particularly with respect to the practical extent of natural gas supply infrastructure investment and the speed of required changes to the energy policies of individual countries. These challenges are particularly great for developing countries, where even the collection of energy statistics is a major challenge, and where it may be more cost-effective to address other priorities.

207. Energy Efficiency – Improving the efficiency of energy conversion and use is the obvious option to improve both energy security and greenhouse gas emissions, but maintaining the focus needed here appears difficult.

208. Carbon Capture and Storage – It is clear that CCS is not just an issue for coal use, but for all fossil fuels, and a major equipment manufacturer had given cause for optimism that the industry can expand to meet future demand. However, there is still a major gap in the long-term business case for CCS.

209. A significant reminder – Mongolian coal development plans have provided a reminder that, where a country is endowed with abundant indigenous coal resources, these will be used to support economic and social development, these being much stronger drivers

http://www.iea.org/ciab/papers/CIAB_Plenary_Discussion_Nov09.pdf�

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than global CO2

210. The reality check – The costs of achieving CO

emissions reduction.

2

211. The Role of the Coal Industry Advisory Board – A role of the CIAB is to advise the IEA Executive Director of the industry’s perspective on these energy and greenhouse gas mitigation issues. To this end, its recent statement on “

emissions reductions and secure energy supplies are substantial, as illustrated by the EPRI studies. A further illustration is the requested electricity price increase of 45% per annum for three years, since modified to 35% and granted at 25%, to support South African infrastructure development to address recent electricity supply security issues.

The Role of Coal in the Post-2012 Greenhouse Gas Reduction Agreement” outlined key elements that governments must include in the new agreement if it is to successfully enable the world’s use of coal to be compatible with greenhouse gas reduction objectives – messages delivered to the IEA Ministerial Meeting in October 2009, well in advance of the COP15 negotiations in Copenhagen.

4.1.2 CIAB Members Questionnaire 212. The world’s response to climate change is now a much more obvious determinant of the

pattern of global coal investment than it was five years ago. The coal industries in developed countries (those subject to near-term carbon constraints) are experiencing subdued domestic growth and challenges to their licence to operate; while the coal industries in developing countries (those that are not subject to near-term carbon constraints) dominate the world’s growth in coal supply and consumption.

213. Does the power of coal as a driver of poverty reduction through electrification mean that coal consumption will continue to rise in developing countries, and that coal-related emissions will therefore also continue to grow in the absence of affordable low emissions technologies? In light of these uncertainties, will investment in coal supply and use be sufficient to meet projected electricity demand?

214. Prior to the meeting, CIAB Members were invited to submit views on the topics covered by the three main Plenary Meeting discussion sessions. The following paragraphs briefly summarise some of the key points raised.

“Greenhouse Gas Mitigation Measures – Implications for the Coal Industry in Developed and Developing Economies”, focussing on the achievability of sufficient greenhouse reductions through CCS; and what possible alternative measures may be available.

215. Carbon Capture and Storage (CCS) for fossil fuels was seen as essential to the cost-effective achievement of greenhouse gas mitigation targets, consistent with securely meeting future energy demand. Although other measures, including carbon credits, coal conversion to liquid fuel, co-firing coal with bio-fuels, re-forestation and increasing power station efficiency were mentioned, none was seen as an effective substitute for CCS. The point was made that only a balanced integrated system of energy efficiency, renewable energy, fossil fuels with CCS and nuclear power can ensure a low-CO2

216. Mandatory efficiency and emissions standards were only seen as possible drivers for investment in modern power plants and CCS technology provided that the technology needed to meet these standards is commercially demonstrated and available. The risk that emissions standards would merely cause a switch of investment from CCS to other forms of generation that meet the CO

, secure and economically efficient future electricity supply.

2 targets in the short term and have a lower

http://www.iea.org/ciab/Post-2012_GHG_Red_Statement.pdf�


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technology risk (such as natural gas) was seen as very real. Many detailed points were raised in respect of the practical implementation of emissions trading schemes and standards, pointing to possible undesirable consequences of such schemes.

217. While some commentated that the coal and electricity industries should not delay deployment of a range of possible measures to increase efficiency, the majority of CIAB Members also emphasised the pressing need to demonstrate the technical and economic viability of CCS on coal-fired electricity generating plant, facilitating its deployment in developed and developing economies.

218. Measures necessary to encourage early development of CCS have been discussed elsewhere14

219. Public acceptance of the need for efficient coal-fired generating plant and the development of CO

and several were highlighted again. These included clarity of international greenhouse gas policy targets and country-specific regulatory and legal frameworks, without which potential investors face unacceptable commercial risks. Several CIAB Members suggested that the provision of sufficient clarity would take several years and emphasised the need for public funding to support investment in CCS demonstration. IEA projections of greenhouse gas emissions reduction from power generation were seen as ambitious.

2

“Energy Sector Investment and the Coal Industry – Implications for Energy Security”, exploring the adequacy of coal production, infrastructure and power generation investment.

storage capacity and infrastructure were also seen as areas needing support from policy makers.

220. CIAB Members supported IEA assessments of the effects of the financial crisis on global

coal investment. Following an increase in planned investment during 2008, in response to substantial rises in the price of internationally traded coal, 2009 saw some projects delayed or cancelled as companies responded to financial pressures and the temporary easing of the growth in global coal demand. The potential for future investment in coal production capacity remains, but the ability to meet future demand also relies critically on the availability of sufficient rail and port infrastructure capacity.

221. In OECD countries, CIAB Members saw competition from gas and renewable energy sources as a detriment to ensuring sufficient investment in coal-fired power station capacity. Uncertainties with respect to future government policies and the influence of public opinion on the response to climate change were also seen as significant factors.

222. In the UK, for example, permission to build new coal-fired electricity generating capacity is conditional on an uncertain commitment to fit CCS technology at some stage in the future. Faced with such an open-ended commitment, the pressure to invest in gas-fired capacity (which does not carry such a commitment) is strong. Additionally, UK power companies are multi-national in nature, providing the option for them to invest in countries with lower commercial risk than the U.K.

223. These factors increase the risks for coal-related investment activity. The IEA was called upon to appeal to member states to take up the possibility of investment grants for new-build, highly efficient, power plants and to promote public acceptance of new coal-fired power stations.

14 See for Example “The Role of Coal in the Post 2012 Greenhouse Gas Reduction Agreement” and “Clean Coal Technologies – accelerating commercial and policy drivers for deployment”


http://www.iea.org/publications/free_new_Desc.asp?PUBS_ID=2011�

http://www.iea.org/publications/free_new_Desc.asp?PUBS_ID=2011�

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224. From a greenhouse gas perspective, the point was also made that an increase in international gas demand could draw additional gas supplies from countries, such as Russia, that may themselves increase coal use as a result of increasing gas exports.

225. In developing countries, Members saw the need to expand electricity supply and combat poverty as likely continuing to outweigh environmental issues. They made reference to continuing high levels of coal-fired power generation investment in developing countries including China and India.

226. They also saw delivering the coal-fired power station investment required in such countries as Russia, South Africa, Indonesia, Columbia and Brazil to meet future electricity demand as a significant challenge.

“Carbon Pricing – Implications for Coal and the Migration of Industrial Activity”, examining the effects of carbon pricing regimes on the coal industry and the potential for re-distributing industrial activity and CO2

emissions between developed and developing economies.

227. Members representing Australia pointed to the effects of carbon pricing on coal production in European countries, and now in Australia. Such schemes were characterised as reducing the future competitiveness of coal in the market place and consequently reducing investment in coal supply. The specific provisions of the Australian scheme were also seen as adversely affecting the competitiveness of Australian coal in world markets.

228. Most Members agreed that, in principle, economic activity will migrate to areas and countries with comparative low-cost production advantages; and this was recognised as an underlying long-term international trend.

229. They also recognised the role of carbon pricing in encouraging investment in low-carbon electricity and industrial production, but expressed concern about the potential mid-term effects of carbon pricing mechanisms on the international competitiveness of energy-intensive industries. In the longer term, unrestrained carbon emissions in any country are unsustainable, but the internationally agreed carbon pricing and other mechanisms necessary to bring about this outcome were seen as being many years away from realisation.

230. Real concern was expressed, particularly amongst Members representing the USA, regarding the potential for energy intensive industries to migrate to developing economies in the medium term, although it proved more difficult to specifically quantify the extent that this would accelerate the long term underlying trend.

231. In response to economic migration driven by differential national responses to carbon pricing, trade sanctions were seen as an attractive ”political fix”; although Members almost universally saw such a reaction as detrimental to international and national economic well-being.

232. Other possible responses mentioned by Members included caps on CO2

prices in countries with industries at risk, the exclusion of particular industry sectors from carbon pricing schemes altogether, and the inclusion of CCS in the Kyoto Clean Development Mechanism. The need to develop suitable technologies, including CCS, to enable industry investment to react effectively to carbon pricing signals was again emphasised.

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4.2 Sustaining the Role of Coal 233. IEA scenarios project total energy demand increases of 20-40% to 2030 (from 2007),

depending on the extent of action taken to mitigate increases in greenhouse gas emissions15

234. A compelling economic and social case can be made for sustaining the role of coal in the future energy mix, given that it is an affordable, reliable and secure source of energy. All fossil fuels must address the challenge of greenhouse gas emissions reduction – most important for coal because it is the most carbon intensive fossil fuel. The following paragraphs highlight recent developments that reflect the challenge which has been accepted by the industry and governments to reduce the emissions from the use of coal in fulfilling its role in the future energy mix.

. In order to maintain a stable and affordable energy supply whilst keeping economic, social and environmental objectives in balance, it is essential that energy be obtained from a wide variety of sources.

4.2.1 Policy and the Role of Coal Australia

National Greenhouse and Energy Reporting Scheme (NGERS) 235. The NGERS Act, passed in 2007, introduces a single national reporting framework for

the reporting and dissemination of information about the greenhouse gas emissions, greenhouse gas projects, and energy production and use of corporations. The NGERS legislation has been primarily designed to underpin an emissions trading scheme and assist with Australia’s international reporting obligations under the Kyoto Protocol.

236. The first annual reporting period for eligible corporations began on 1 July 2008 with a consolidated data lodgement of 3 October 2009

237. The legislation prescribes measurement methodologies for a range of emissions and energy sources, including fugitive emissions from coal mining both from open cut and underground mines. Industry is in consultations with Government regulators on how fugitive emissions from open cut and decommissioned mines sites should be treated and developed going forward (see also paragraphs 282-287 on the Carbon Pollution Reduction Scheme).

Renewable Energy Target (RET) 238. On 20 August 2009 the Senate passed a Bill to establish a national Renewable Energy

Target (RET) scheme to expand the previous Mandatory Renewable Energy Target (MRET) by over four times to 45,000 gigawatt-hours in 2020. This is aimed at achieving the Government’s 20% renewable energy target by 2020.

239. The legislation allows for certain power generation from waste coal mine gas to receive de facto eligibility under the RET. This assistance will apply to a small number of existing operations only, and represents a transitional measure from the New South Wales GGAS scheme. The power generation covered will be capped at 425 gigawatt-hours in 2011 and 850 gigawatt-hours for the years 2012 to 2020. This assistance is additional to the overall RET target.

15 OECD/IEA “World Energy Outlook 2009” (2009)

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South Africa

240. While South Africa’s major energy source will remain coal in the foreseeable future, numerous drivers indicate the need to reduce coal’s current 88% share of the energy mix to below 70% by 2030. To achieve this, a much higher proportion of nuclear power generation is proposed by 2030, while additional renewable energy options will also be pursued. Pumped-storage and gas-fired power stations will be established to meet peak demand, while electricity imports from neighbouring countries will also be negotiated.

South African Coal Roadmap 241. Substantial interest and support has been declared at the proposal for the compilation of

a South African Coal Roadmap. The proposal was launched to a broader industry audience in November 2007 and discussions with government representatives are ongoing in order to formalise the proposed collaboration. However, in principle, support was crystallised with the Minister’s opening speech at the Carbon Sequestration Leadership Forum meeting in Cape Town in April 2008.

242. The Department of Minerals and Energy has been supportive of this initiative and the founding documents and governance structures have already been developed. Significant financial commitments have been received from industry stakeholders. However, the recent split of the Department of Minerals and Energy into a Department of Energy and a Department of Mineral Resources has delayed implementation of the work programme.

243. Government has begun work on the development of an Integrated Energy Plan and progress is anticipated during 2010.

Energy efficiency 244. As a continued contribution to the South African Government Department of Minerals and

Energy's Energy Efficiency Strategy, industry has continued with the Energy Efficiency Accord. Eskom is undertaking an aggressive national demand-side management (DSM) programme intended to effect permanent reductions in demand by approximately 3,000MW by 2011 and a further 5,000MW in the subsequent years to 2026. The programme’s objective is to alleviate imminent supply constraints and obviate the need for more costly supply options that are currently under consideration.

Long–Term Mitigation Strategies 245. Early in 2008, the then South African Department of Environmental Affairs and Tourism

(DEAT) released the findings of the Long Term Mitigation Scenario (LTMS) process. This report outlines a range of strategies for scenarios of possible future climate action, notably long-term emissions reduction scenarios, the technical requirements in the various sectors and their cost implications. In addition, various national departments, provinces and cities are refining their sector plans in line with the National Climate Change Response Strategy. The restructured Department of Water and Environmental Affairs (DWEA) is currently developing the National Climate Change Policy, with a green paper to be produced in April 2010, a white paper in December 2010 and expected finalisation early in 2011. This policy may have stringent requirements on the country, depending on how the international climate negotiations unfold.

Tax on non-renewable electricity generation 246. Effective 1 July 2009, South Africa’s National Treasury has introduced a 2c/kWh levy on

all electricity generated in South Africa from non-renewable energy sources (including all fossil fuels and uranium). The Department of Energy is also commissioning a review of the Renewable Energy White Paper Policy and Target.

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247. While South Africa’s major energy source will remain coal in the foreseeable future, numerous drivers indicate the need to reduce coal’s current 88% share of the energy mix to below 70% by 2030. To achieve this, a much higher proportion of nuclear is proposed by 2030, while additional renewable energy options will also be pursued. Pumped-storage and gas-fired stations will be established to meet peak demand, while electricity imports from neighbouring countries will also be negotiated.

Poland

248. The priorities in Polish energy policy are security of energy supplies and energy effectiveness based on indigenous resources, increased use of renewable sources of energy, development of competitive markets for fuels and energy and limiting the impact of the energy industry on the environment.

249. The dominant role of coal in its energy balance and de-capitalized electricity generation, transmission and distribution infrastructure make reducing CO2

250. Improved energy efficiency will reduce the impact of growth in demand for fuels and energy, which in turn will contribute to increased energy security, due to reduced dependence on imports, and will limit the impact of energy on the environment by reducing emissions of greenhouse gases.

emissions an especially great challenge for Poland. Coal accounts for about 59% of primary energy consumption and about 93% of electricity generation, the highest share in the EU. Only 5% of primary energy and 3.4% of the electricity is generated from renewable sources and there is no nuclear energy.

Improvement of Energy Effectiveness 251. Poland intends to promote activities enhancing effectiveness in the areas of generation,

transmission, distribution and utilisation of energy. One of the proposed instruments of support is the system of “white certificates“, which provides financial benefits for entities achieving greatest energy savings. Poland expects dynamic growth in electrical and thermal energy generation from high-efficiency cogeneration technology, particularly in small plants below 1 MW. Minimum efficiency standards will be introduced for equipment and products consuming energy and identification of their energy intensity; and the Ministry of Economy will also run information campaigns promoting rational consumption of energy.

Limiting the impact of the energy industry on the environment 252. Poland reduced CO2 emissions by 32% between 1988 and 2005 and will strive to reduce

CO2 emissions from the fuel-energy sector by 20% from their 2005 level by 2030, also achieving the emission ceilings for NOX and SO2

• reducing the demand for fuels and energy by improving energy generation, transmission, distribution and consumption efficiency;

from the combustion of fuels for power generation specified in the Accession Treaty and complying with maximum atmospheric dust concentrations. Measures to achieve these targets include:

• changing the structure of energy generation towards low-carbon technologies, including renewable and nuclear energy; and

• developing and implementing technologies to reduce emissions into the air in the processes of acquiring and producing fuels and energy.

253. Coal will remain an essential fuel for the foreseeable future, supporting power generation,

energy security and economic growth. In terms of generating electricity from coal, a fundamental modernization of generation assets and construction of additional capacity based on the best available technologies are needed. Carbon capture and storage (CCS)

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technology is of particular importance for Poland, within the framework of the development of clean coal technologies, although there are still concerns including those related to the safety of CO2

254. Poland foresees a very active participation in the EU CCS demonstration projects.

transport and storage. New, high efficiency power stations are a necessary pre-requisite to CCS.

Increased security of energy supplies 255. Security of energy supply will be based on indigenous resources of raw materials, coal in

particular, and the development of technologies facilitating manufacture of liquid and gas fuels from domestic raw materials. In the long term there is no possibility of reducing greenhouse gas emissions in Poland without the use of nuclear and renewable energy, although this will not eliminate the Polish energy system's dependence on coal. Nuclear energy will only be available in 15 years at the earliest, while renewable energy is expensive, and these energy sources will generate a total of only 30-40% of the required energy.

Enhanced use of renewable energy supplies (RES) 256. The development of renewable power generation is of substantial importance to Poland’s

energy policy. Targets are to achieve a 15% share of RES in final energy consumption by 2020 and a 20% share by 2030. It is also planned to achieve a 10% share of biofuels in the transport market by 2020 and to

Development of competitive markets for fuels and energy

increase the use of second-generation biofuels.

257. The Ministry of Economy intends to solve the problem of dependence on the supply of gas and oil from one source, remove barriers for changing a supplier of electrical energy and gas, change the operating principles of platforms for trade in electricity and introduce market mechanisms in establishing prices for heat.

Investments in the hard coal mining industry 258. As it is vital to ensure long-term stable supplies of high quality coal, it is considered

essential to execute investment projects related to reconstruction of the metallurgical and thermal coal resource base. Investment activities carried out by 2015 should:

• ensure continuous and failure-free mine operation, including adjustment of capacities and output to market needs, replacement of production capacity losses, modernization of transport and ventilation passages and replacement of machines and equipment; and

• further restructure coal mines, including technical and technological improvement in conditions ensuring safety at work, production concentration, coal quality improvement and measures to minimize the unfavorable effects of mining industry on the environment.

259. The strategy also foresees execution of projects related to development of new coal

processing technologies to ensure compliance with the increasing requirements of its customers with regard to new, clean combustion processes. Production of qualified coal fuels will be developed, which are characterized by high calorific value and low sulfur content intended for burning in low emission, specially designed, boilers with retort or grate furnaces (e.g. fuels: EKORET, EKO-FINS, RETOPAL etc.).

Russia

260. Russia spends an estimated 3.5 times more on energy than the European average. The Russian President and government are now calling for the implementation of major

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energy saving and energy efficiency measures and alternative energy generation. In 2008 Russian President Medvedev issued an executive order requiring a 40% reduction in the energy-output ratio within Russian GDP by 2020. Government authorities are preparing a new version of the energy efficiency and energy savings law.

261. Russian power utilities also await government procedures and laws concerning the competitive power capacity market, which should start to operate in the near future and become one of the main funding sources for Russian power plant investment programmes. The Russian Government has adopted a road map for the development of new electricity generation capacity to 2020 and has signed shareholder agreements with major shareholders of Russian power generating companies. These include obligations to install new power capacity by specified times.

262. Because of financial crisis and lack of credit resources, the Russian government has allowed some generating companies to postpone part of their investment projects.

263. Currently, about 50% of the electricity market in Russia is liberalized and about 50% is regulated. The government has adopted a schedule to gradually increase liberalization so that by 2011 100% of the market outside the household market will be using free prices; and this schedule will be maintained despite the financial crisis.

Spain

264. Spanish policy with respect to coal is contained in the “National Plan for the Strategic Reserves of Coal 2006-2012 and The New Model for the Development of the Coal Fields” (“Plan National de Reservas Estratégicas de Carbón 2006-2012 y Nuevo Modelo de Desarrollo Integral sostenible de las Cuencas Mineras” or “The Plan”), signed on 28 March 2006 by the Government, the Unions and Carbunión (Associatión of Coal Mining Companies).

265. It sets out for the period 2006-2012 the development of coal production, consumption and workforce numbers, as well as the subsidies regime and production reduction all based on (CE) 1407/2002 covering State Subsidies to the Coal Industry.

266. The Plan establishes four types of direct aid to the coal industry, as described in directive (CE) 1407/2002, and includes a series of aids for the development of mining regions, infrastructure, business projects, education, environmental issues and new technologies.

United Kingdom

267. The Department of Energy and Climate Change (DECC) was created in October 2008, amalgamating elements of the Department for Business, Enterprise and Regulatory Reform (BERR) and the Department for Environment, Food and Rural Affairs (DEFRA) to bring together energy policy and climate change mitigation policy.

268. The Energy Act 2008 was given Royal Assent on 26 November 2008, implementing legislative aspects of the 2007 Energy White Paper “Meeting the Energy Challenge”

269. The Energy Act, alongside the Planning Act 2008 and Climate Change Act 2008, ensures that Governmental legislation underpins the long term delivery of their energy and climate change strategy.

.

270. The Climate Change Act had several key provisions

• Legally binding targets: Green house gas emission reductions through action in the UK and abroad of at least 80% by 2050, and reductions in CO2 emissions of at least 26% by 2020, against a 1990 baseline. The 2020 target will be

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reviewed soon after Royal Assent to reflect the move to all greenhouse gases and the increase in the 2050 target to 80%.

• A carbon budgeting

•

system which caps emissions over five year periods, with three budgets set at a time, to set out our trajectory to 2050. The first three carbon budgets will run from 2008-12, 2013-17 and 2018-22. Government announced the levels of the first three budgets in April 2009, requiring the UK to cut emissions by 34% on 1990 levels by 2020.

The creation of the Committee on Climate Change

271. DECC published its “UK Low Carbon Transition Plan” on 15 July 2009, setting out how the UK will meet the 34% cut in emissions on 1990 levels by 2020. As well as various household and transport provisions, this states that around 50% of the annual emissions cuts between now and 2020 will be achieved by further “greening” of the electricity mix. It targets 40% of the electricity use in 2020 coming from low carbon sources (30% from renewable energy sources and the rest from nuclear and clean coal), with carbon emissions from electricity all-but eliminated by 2050.

, a new independent, expert body to advise Government on the level of carbon budgets and where cost effective savings could be made. The Committee will submit annual reports to Parliament on the UK’s progress towards targets and budgets to which the Government must respond, thereby ensuring transparency and accountability on an annual basis. The Committee has subsequently recommended to Parliament that there should be no new, unabated, coal-fired plant in the UK. However, it appears very probable that Government will fund first-of-kind CCS plants.

4.2.2 Greenhouse Gas Reduction Measures and Emissions Trading United States of America

American Clean Energy and Security Act (Waxman – Markey Bill) 272. The United States House of Representatives passed the American Clean Energy and

Security Act of 2009 (H.R. 2454) on 26 June 2009 by a narrow majority, reflecting members’ serious concerns regarding the impact of the bill on American jobs, the economy and energy security.

273. The 1,427 page Waxman – Markey bill would establish U.S. greenhouse gas emissions reduction targets from 2005 levels of 17% by 2020, 42% by 2030 and 83% by 2050. It proposes to achieve these reductions by imposing limits on emissions and establishing a traded market for emissions permits (i.e. “cap-and-trade”). It would require certain industries to reduce their output of CO2

274. Specifically, the bill would establish a fixed quantity of total emission allowances for each calendar year starting in 2012. Covered entities would be allocated a percentage of these “free allowances” – most of which phase out by 2030 – entitling them to emit CO

emissions to specific target levels through to the year 2050 and covers many areas of the U.S. economy including electricity producers, oil refineries, natural gas suppliers and energy-intensive industries like iron, steel, cement and paper manufacturers. Covered industries would be granted emissions permits or “allowances” on an annual basis up to their allowable target or “cap” and would be required to acquire permits for emissions exceeding this threshold. Companies able to reduce emissions below the permitted level could retain unused permits for future use or sell them on a traded market to firms requiring additional permits. If a company’s emissions exceed its permits, Waxman – Markey would impose a fine equal to twice the fair market value of the permits it should have purchased.

2. They

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would also be allowed to purchase carbon offsets generated by clean energy projects around the world in order to meet a portion of required emission reductions. The U.S. electric utility industry would be allocated 43.75% of the free allowances in the first year of the program, a figure which declines over time to 7% by 2029. Based on 2007 emissions levels, 83% of the electric utility industry’s emissions would be covered by allowances in 2012, 62% in 2025, but only 10% by 2029.

275. The bill would establish a strategic allowance reserve pool intended to protect emitters from increases in the price of permit allowances. The reserve pool would contain 2.7 billion permit allowances (each permit equal to the one ton of CO2) taken from allowances originally reserved for the future.16

276. Waxman – Markey also contains a renewable electricity standard (“RES”) which would require large utilities to generate an increasing percentage of their electricity from renewable sources. Qualifying sources include wind, solar, geothermal, biomass, landfill gas, coal-mine methane, hydropower and certain waste-to-energy projects. Electric utilities would be required to meet 20% of their electricity demand through renewable energy sources and energy efficiency measures by 2020. In addition, the bill would establish natural gas performance standards for new coal-fired power plants permitted in 2020 and thereafter.

Every year a certain portion of this pool would be available for purchase at a minimum price of $28 per allowance. Further, a covered entity may purchase no more than 20% of its annual permits from the reserve pool and only 5% of the entire reserve for a given year can be auctioned. Finally, the bill proposes to refill the reserve pool with international forestry offsets.

277. The National Mining Association (“NMA”) has conducted a state-by-state analysis of the impact of Waxman – Markey. It concludes that most states will not have enough allowances to cover their emissions from electricity generation, resulting in higher electricity costs for consumers particularly in Midwest and Southern states. To make up for the allowance shortfall, states will be forced to seek higher cost electricity sources, reduce electricity production and consumption and/or purchase emissions allowances as well as domestic and international offsets.

278. According to the Heritage Foundation, a leading U.S. public policy research institute, Waxman – Markey’s cap-and-trade provisions would result in more than one million job losses over the 2012 – 2035 timeframe. Within the coal industry, an analysis of H.R. 2454 by CRA International found potentially severe impacts on employment levels.

Emissions Trading 279. The Chicago Climate Exchange was established as a private industry, self-regulatory,

voluntary organization that manages a market for trading greenhouse gas emissions. Although located in the US, Chicago Climate Exchange participation is multi-national. The exchange began continuous electronic trading of greenhouse gas emission allowances in December 2003.

280. Chart 5 shows monthly electronically trading volumes to January 2010. The average monthly volume traded in 2008 was 5.8 million tonnes, compared to the previous highest monthly peak of 3.7 million tonnes. Volumes have been substantially lower in 2009, returning to an average of less than 3.6 million tonnes/month. Trade in January 2010 was less than 0.3 million tonnes.

16 1% of 2012 – 2019 allowances, 2% of 2020 – 2029 allowances and 3% of 2030 – 2050 allowances.

http://www.heritage.org/research/energyandenvironment/wm2450.cfm�



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281. Prices increased dramatically during 2008 to reach over $7/tonne of CO2 in May, the

month of peak trading volume, and declined just as dramatically to about $1.65/tonne at the end of the year (see Chart 6 below). Following a slight recovery to above $2/tonne in the first quarter of 2009 prices have declined steadily and have been in the range 10-15c/tonne since September 2009, lower than ever seen before.

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Australia

Carbon Pollution Reduction Scheme (CPRS) 282. On 13 August 2009, legislation to implement the Government’s Carbon Pollution

Reduction Scheme (CPRS) was defeated in the Senate. The Government must wait three months before it can re-introduce the Bill for a vote, which means that the earliest possible date for another vote on the Bill will be 16 November 2009, just 21 days prior to the UNFCCC Copenhagen meetings.

283. Government has stated that they will seek to pass the CPRS Bill before Copenhagen. If the Bill is defeated a second time by the Senate this will provide the Government with a trigger for a double dissolution of the Parliament, a precursor for an early Federal election for both houses.

284. Pressure is now on the Opposition to successfully delay the vote on the CPRS Bill until after Copenhagen and/or present detailed amendments to the Bill as part of negotiations with Government to pass the Bill in November 2009. The Opposition has released a set of key negotiating principles for emissions trading which include that coal mine fugitive emissions should be treated in the same way as proposed in the US and European schemes.

CPRS Impact on the coal industry. 285. The Australian coal industry through the Australian Coal Association was in formal

negotiations with Government up until early June 2009 when it was evident that both parties had reached a stalemate on their positions over how the coal industry should be treated under the proposed CPRS.

286. Modelling commissioned by the industry into the impacts of the CPRS on the coal industry found that in the first 10 yrs of the scheme:

• the industry qualifies for emission intensive trade exposed (EITE) assistance using the government’s own methodology;

• CPRS will impose an additional cost on industry of around A$14.5 billion;

• 16 Mines would close prematurely; and

• there would be10,000 job losses in the coal industry from premature mine closures by 2021.

287. Below is an extract from the modelling undertaken by Acil Tasman into the impact of the

CPRS on the industry:

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Table 8 – Impact of CPRS on the Australian Coal Industry

Source: Acil Tasman, 2009

However, the Government has rejected inclusion of the industry in EITE at the 66% level (66 % free emission permits) for 10 years and the alternative industry proposal of phased inclusion of fugitive emissions, with proposed assistance of only A$750 million over 5 years compared to estimated CPRS costs for the industry of a $14.5 billion over 10 years. National Low Emission Coal Council & Carbon Storage Taskforce

288. This Council in cooperation with the national storage taskforce is in the final stages of crafting a national low emissions coal strategy for Australia. Industry has participated in the strategy development process; and on the widespread demonstration and deployment of CCS in Australia has stressed that the following issues be addressed as a priority:

• issues around community acceptance;

• defining storage availability;

• cost effective demonstration portfolio

• ongoing research support;

• exemption from CPRS and better taxation policy settings;

• transitional support for CCS Flagship projects and multi-user storage hubs;

• supportive regulatory framework;

• streamlining of project approvals; and

• development of the necessary skills base. 289. In relation to the national research program, the Council has established the Australian

National Low Emissions Coal (ANLEC) R&D organisation to lead and enhance the coordination of Australia’s research effort.

Energy White Paper 290. In late 2008 the Government undertook to develop an Energy White Paper, with industry

involved through a high level consultative committee and workshops.

291. The Energy White Paper will cover fossil and renewable energy resources including: exploration and development of energy; energy conversion; energy transmission and distribution; energy consumption; investment; energy trade; energy related technologies

Coal industry

Overall NSW QLD

2015 $1,300m 12 16.8 $1,400m 2,500 7,600 2,300 200

2018 $1,600m 13 17.6 $1,500m 3,000 8,800 2,300 700

2021 $1,900m 16 21.6 $1,900m 3,300 9,900 2,300 1,000

Effects of premature mine closures

Annual decline in revenue

from coal sales

Employment reduction

Annual decline in Coal

production (mt)

Number of mines affected

By year: Employment reduction in the coal

industry by State

Annual cost of CPRS to

Coal Industry

Coal industry

Overall NSW QLD

2015 $1,300m 12 16.8 $1,400m 2,500 7,600 2,300 200

2018 $1,600m 13 17.6 $1,500m 3,000 8,800 2,300 700

2021 $1,900m 16 21.6 $1,900m 3,300 9,900 2,300 1,000

Effects of premature mine closures

Annual decline in revenue

from coal sales

Employment reduction

Annual decline in Coal

production (mt)

Number of mines affected

By year: Employment reduction in the coal

industry by State

Annual cost of CPRS to

Coal Industry

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and services; and capacity building and skills. It is to be completed by the end of 2009 following release of key issues papers and responses to a draft Energy Green Paper scheduled for mid to late 2009.

New Zealand

292. The Climate Change Response Act 2002 was amended by the outgoing government in September 2008 to introduce an emission trading scheme with the following main elements:

• It is intended over time to cover all gases and all sectors.

• The New Zealand government will issue New Zealand units (NZUs) under the scheme and will back these one for one with its allocated AAUs under the Kyoto Protocol. There will be no restrictions on flows of NZ AAUs out of New Zealand and no provision for any price caps in the scheme.

• Essentially any person with an obligation under the scheme must surrender annually to the government the number of emission units equal to the assessed emissions associated with their activities. The emission factors and methodologies for deriving the number of units required are to be set by way of regulation.

• There is to be a limited free allocation of NZUs by the government to trade-exposed industries who (on aggregate) at best may receive 90% coverage for their 2005 emissions. There is also provision for a sliding scale automatic reduction of that allocation over time.

293. For “stationary energy” (i.e. importing or mining coal or gas and including fugitive

emissions of methane from mining; using geothermal fluid or combusting waste oils for electricity generation or industrial heat; refining petroleum for energy or feedstock purposes) the obligations apply from 1 January 2010; and purchasers of more than 250 kilo tonnes of coal or 2PJ of gas per year may opt in to the scheme.

294. Following the November 2008 elections the incoming government has established a special Select Committee to look at the framework of the ETS and make recommendations for change. It is likely that there will be changes to the ETS, focusing on introducing an intensity based allocation system (rather than absolute emissions), a delay in entry into the scheme for the stationary energy and industrial processes sector, and a ceiling price on units for an initial period.

295. The Government has recently announced New Zealand’s proposed emission reduction targets for the next commitment period under the Kyoto Protocol to 2020 as ranging from 10% below 1990 levels to 20% below 1990 levels depending on various preconditions being met.

Japan

296. Japanese companies have been eager to form technological co-operations with developing countries. For example, Japanese Power Utilities have been actively involved in thermal efficiency improvement programs for coal fired power plants under the framework of “Asia Pacific Partnership on Clean Development and Climate”.

297. In addition, several Japanese companies have initiated work on the commercial use of clean coal technologies, which will sustain the role of coal by mitigating its environmental burden. As an example, Mitsubishi Heavy Industries Ltd. announced in June 200917

17 http://www.mhi.co.jp/en/news/story/090622english.html

that

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it would participate in a project to build the world’s first commercial-scale integrated gasification combined cycle (IGCC) power plant with carbon capture and storage capability in Australia.

298. In July 2008, the Japanese Cabinet approved the “Action Plan for Establishing a Low Carbon Society”. The Plan indicates that:

• as a long-term objective, Japan will reduce GHG emissions by 60-80% from current levels by 2050;

• the mid-term objective for total GHG emissions in 2020 will be announced within the next year; and

• a domestic emissions trading system will be introduced in fall 2008 and be tested.

Prime Minister Aso has now announced the mid-term objective of a 15% reduction in GHG emissions from 2005 levels by 2020.

299. Since the trial introduction of an Integrated Domestic Market for Emissions Trading in October 2008, 715 organizations have entered the Market. Of these, 220 organizations show voluntary reduction targets and need to obtain Kyoto Mechanism Credits or Domestic Credits when they cannot achieve targets with their own reductions.

300. In July 2009, the Japanese government legislated for a shift in energy supplies from fossil fuels to renewable energy and nuclear power. Electric power companies might be obliged to employ 50% or more non-fossil fuel sources by 2020.

South Africa

301. The Designated National Authority (DNA) to approve proposed Clean Development Mechanism (CDM) projects resides within the South African Department of Minerals and Energy. To date, there are 125 CDM projects18

Germany

submitted to the DNA – 96 Project Idea Notes (PINs) and 29 Project Design Documents (PDDs). 15 of the PDDs have been registered by the CDM Executive Board as CDM projects (4 Issued with CERs), and 14 are the validation stage and/or request for review stage of the project cycle. The projects submitted to the DNA for initial review and approval cover: bio-fuels; energy efficiency; waste management; cogeneration; fuel switching and hydro-power, and cover sectors like manufacturing; mining; agriculture; energy; waste management; housing and residential.

302. Compared to 1990, carbon dioxide emissions are estimated to have fallen by 5% to 4,197 million tonnes in 2007 for the EU27 countries, largely due to Eastern Europe. Emissions rose by 1% in the EU15 countries, to 3,405 million tonnes over the period. Without the sharp reductions in emissions from Germany and the UK, emissions in the remaining 13 EU countries would have increased by16%.

303. For the EU-27, the carbon dioxide emissions of plants which are covered by the emissions trading scheme are to fall by 21% from 2005 to 2020. The target for the second period (2008-2012) is 2,083 million tonnes per annum, falling to 1,720 million tonnes per annum by the end of the third period (2013-2020).

304. Relevant from coal perspective are the new European Union standards for carbon

18 For up to date project details see http://www.dme.gov.za/dna/dna_project_portfolio.stm

http://www.dme.gov.za/dna/dna_project_portfolio.stm�

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dioxide sequestration, the new CCS guidelines, and a new EU-ETS guidelines which will fix emissions limits for all plants (as part of the emission trading system) from 2013 onwards. The plan is to reduce the fixed allowances by a further 21% (reference year 2005) by 2020, with fully auctioned distribution of certificates for power generation.

Russia

305. Kyoto protocol mechanisms (particularly emissions trading) don’t function properly in Russia and it is difficult to access carbon finance. However, in December 2008, SUEK received an award and special diploma for "Best Environmental Project of the Year" from the Ministry of Natural Resources and Ecology of the Russian Federation. This was given for a SUEK project "Recovery of Degasation Methane at Mines of OAO SUEK-Kuzbass", aimed simultaneously at increasing the safety of miners by withdrawing methane to the surface, production of electrical and heat energy from the methane and sale of the methane within the Kyoto Protocol. The pilot 1 MW gas thermal power mini-station was launched at the S. M. Kirov mine in August 2008.

4.2.3 Power Station Emissions Control/Mining Regulations United States of America

306. On 30 September 2009, Senators John Kerry and Barbara Boxer released a discussion draft of a proposed U.S. Senate climate bill. As with the House bill, the centrepiece of the 801 page Senate proposal is a cap-and-trade system for greenhouse gas emissions. Targeted emissions cuts for 202019 under Kerry – Boxer are increased to 20% from 17% in the Waxman – Markey Bill20 on the basis that the U.S. recession has already dropped CO2

307. Like Waxman – Markey, the Senate draft would allow the U.S. Environmental Protection Agency (“EPA”) to set greenhouse gas emissions performance standards for new coal-fired power plants. However, a major difference with the House bill is that the Kerry – Boxer proposal would not pre-empt the EPA from regulating greenhouse gases under many existing sections of the Clean Air Act. This would have the practical effect of allowing EPA to set emissions standards when issuing permits for existing power plants under the agency's New Source Review program.

output significantly, thus making a higher target achievable.

308. The so-called “pre-emption” issue is expected to be a major point of contention in the eventual Senate debate. The absence of restrictions on EPA would likely result in a dual program consisting of a cap-and-trade system as well as environmental regulatory requirements, effectively allowing EPA to lower the limit on emissions below the national cap. Adding to the dynamics is EPA’s release of proposed rules, issued on the same day that the Senate climate bill was made public, covering CO2

309. Timing of full Senate consideration of climate legislation is an open question with the bill now proceeding into committee work. There is an increasing likelihood that Senate lawmakers will not focus in earnest on climate legislation until 2010, which would add election-year complexity to the situation.

emissions from new or expanded industrial sources emitting in excess of 25,000 tons per year. Under these rules, EPA would assume authority under the Clean Air Act as early as 2011 for greenhouse gas emissions of an estimated 14,000 power plants, refineries and factories.

19 From 2005 levels 20 See section 4.1.3

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Japan

310. The ambient air quality standard for PM (Particulate Matter) 2.5 and water quality standard for 1,4 Dioxane are under discussion by government officials, but standards have not yet been agreed.

311. While no compulsory standard for CO2 has been introduced, each major industry is encouraged to formulate and disclose a quantitative reduction target. In April 2007, the Federation of Electric Power Companies of Japan (FEPC) adopted a revised target to reduce by almost 20% its FY1990 average CO2 emission intensity between FY2008 and FY2012. In parallel, the Ministry of Environment (MoE) published the CO2 emission intensity of each electricity retailer for the first time. The published data are used for large business entities to calculate their CO2 emissions from their electricity consumption and to report GHG inventories to the MoE. CO2

312. Currently, power companies must calculate and report GHG inventories for each power plant, but will report on a company basis after FY2010 in compliance with the “Partial Amendment to the Law Concerning the Promotion of Measures to Cope with Global Warming”.

emission intensities and GHG inventories continue to be updated annually from 2007.

South Africa

313. Significant progress has been made with the National Air Quality Framework document guiding the implementation of the National Environmental Management Air Quality Act. A set of ambient air quality standards has been proposed which allows for the introduction of stricter air quality standards in a phased manner. Stakeholder input has been obtained and these standards are now being reviewed by Standards Committees via the mandated South African National Standards process. Emission limits have also been proposed for the various sectors of industry and these too are currently being reviewed by the relevant Committee. The proposed emissions limits will require that all new coal-fired power stations include flue gas desulphurisation technology. Two Air Quality Management Priority Geographical Areas (Vaal Triangle and Mpumalanga) have been declared in terms of the Air Quality Act. These two areas encompass all except one of Eskom’s coal-fired power stations. Detailed air quality management plans have to be developed for these priority areas and this is being achieved through liaison between government and stakeholders.

Spain

314. Since 1 January 2008, existing generation plants have been subject to the emission limits established in Directive 2001/CE of 23 October 2001. Existing Spanish coal-fired plants will either operate for a maximum of 20,000 hours in the period 2008-2015, according to article 4.4 of the Directive, or will install the equipment necessary to comply with the Directive’s emission limits.

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4.3 Investment in Coal Supply, Transportation and Use 4.3.1 Investment Overview 315. In aggregate, coal industry investment in sustaining current production facilities and

developing new projects increased substantially in 2007 and 2008 in response to the increasing demand for coal and increasing prices for internationally traded coal.

316. However, there is evidence of widespread reductions in capital expenditure for 2009 and 2010 as companies respond to the challenges posed by the global financial crisis. For example Xstrata’s planned coal production expansions of 20-30 million tonnes have effectively been pushed back 12-18 months, while Anglo Coal has closed down some high cost coal production capacity and Anglo American has announced that Group (i.e. all

317. In the USA, Massey Energy announced that capital expenditure will be reduced back from US$700 million in 2008 to US$300 million in 2009, closer to previous years’ levels and to US$100-200 in 2010. Also, in Canada, Teck Cominco (who acquired Fording Canadian Coal Trust in October 2008) announced in April 2009 a two-thirds reduction in aggregate sustaining and development capital expenditure.

mineral mining) capital expenditure plans for 2009 are being cut by more than 50%, primarily by re-scheduled new project expenditure.

318. Conversely, companies such as Indonesia’s PT Bumi Resources continue on track to achieve large increases in coal production capacity.

319. In many cases, capital expenditure adjustments are only reported on a group company basis (including iron ore, gold, uranium mining etc.), making it difficult to identify the specific affects on coal production capacity. However, coal suppliers have emphasised that deferment of coal production capacity expansion plans does not in general impair longer term development potential.

4.3.2 Specific Investment Plans and Projects United States of America

320. According to the USA environmental organisation the Sierra Club, only 59 of 220 coal-fired plants planned and in various stages of permitting since 2001 remain active, with 24 projects cancelled in 2008 and another 9 projects cancelled in early 200921

321. The Prairie State Energy Campus, Illinois, a 1,600 MW mine-mouth coal-fired generating plant with state-of-the-art emissions control technologies, is currently under construction and on schedule. Operations are expected to commence in 2011 to 2012. Peabody is a 5 percent owner in conjunction with eight public power agencies, and will invest approximately $60 million in Prairie State in 2009.

.

322. Production at Peabody’s Bear Run Mine, Indiana, is expected to begin in early 2010 at 2 - 3 million short tons, growing thereafter. Approximately $100 million of the project's approximately $350 million investment is expected to occur this year.

Canada

323. In British Columbia, the Herman coal mine project proposed by WCC received 21 Reuters, Los Angeles, 1 May 2009

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environmental assessment approval in November 2008 and can now proceed with mine development. The open-pit mine has a capacity to produce 0.8-1.1 million tonnes/year of metallurgical coal over its 10-year life, which will be hauled by truck to WCC’s nearby Wolverine coal mine for processing. Capital costs are estimated at CAN$55 million.

324. In Nova Scotia, the Minister of Environment approved the environmental assessment of the proposed Donkin underground exploration project in December 2008. Xstrata was granted the right to develop the Donkin coal block in December 2005 and the Donkin Coal Block Development Opportunity Act was passed in November 2007. Xstrata completed its feasibility study and submitted the project environmental impact study in October 2008. A long-wall mining operation could start producing 3.7 and 5.2 million tonnes/year by 2014 and the estimated life of the mine is 20-30 years. Xstrata owns 75% of Donkin Coal Limited and Erdene Gold owns 25%.

325. There are still six previously proposed coal projects awaiting environmental assessment approval from the B.C. government:

• the Roman metallurgical coal mine project (Peace River Coal Inc.) - a new open-pit coal mine with a production capacity of 2-4 million tonnes/year and a mine life expectancy of 15 years;

• the Gething metallurgical coal mine project (Dehua International Mines Group Inc.) – a new underground mine and a coal preparation plant projected to produce 2 million tonnes/year over a 40-year mine life;

• the Lodgepole metallurgical coal mine project (Cline Mining Corp.) - planned to produce 2 million tonnes/year of metallurgical coal for export;

• the Horizon metallurgical coal mine project (Peace River Coal Limited Partnership) - planned to produce 2 million tonnes/year of metallurgical coal; and

• the Mount Klappan anthracite project (Fortune Minerals Ltd.) - an open-pit mine and a preparation plant with anticipated production of 1.5 million tonnes/year.

326. In Alberta, Sherritt and the Ontario Teachers’ Pension Plan applied for an environmental

assessment for a coal gasification project in early January 2007. The $1.5 billion Dodds-Roundhill gasification project involves mining sub-bituminous coal and processing it into gas. Production will begin in 2011 and the project will reach its designed capacity of 320 million cubic feet per day of synthetic gas by 2012. Coal reserves and resources in the project area were estimated at 320 million tonnes and a 40-year mine life is expected.

Australia

327. Investment in both greenfield and mine expansions in Australia has continued despite the global slowdown, albeit with delays to some uncommitted projects. Projects recently completed or due for completion during 2009 and 2010 include the following:

Table 9 – Australian Coal Mine Expansion Projects

Mine Coal Type Company Mine Export Capacity Mtpa

Lake Lindsay Coking/Thermal/PCI Anglo 3.5 Mt Arthur Coal expansion Thermal BHP Billiton 6.0 Rix’s Creek Thermal Bloomfield Collieries 1.0 Airly Thermal Centennial 1.0 Abel Thermal Donaldson 2.0 Moorlaben OC Thermal Felix Resources 8.0 Boaggabri expansion Thermal Idemitsu 4.5

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Mine Coal Type Company Mine Export Capacity Mtpa

Lake Vermont Coking/PCI Jellinbah Resources 3.0 Middlemount Coking/Thermal Macarthur 2.0 Clermont Thermal Rio Tinto Coal

Australia 12.0

Glennies Creek O/C Thermal Vale 0.5 Rocglen Thermal Whitehaven 0.5 Narrabri North Thermal Whitehaven 3.0 Sunnyside Thermal Whitehaven 1.0 Glendell Thermal Xstrata 2.0 Blakefield South Coking/Thermal Xstrata 6.0

Source: Xstrata Coal

328. Realisation of export expansion in Australia is dependent on the parallel expansion of export infrastructure to allow the new production capacity access to markets. Significant expansions are currently underway and in planning for completion over the period to 2010 which collectively should increase export capacity by 50Mt compared to 2008. Details are shown in the following table:

Table 10 – Australian Coal Mine Expansion Projects

Export Corridor Infrastructure Export Capacity Mtpa 2008

Export Capacity Mtpa 2009

Export Capacity Mtpa 2010

Hunter Valley PWCS Port 102 104 113 Hunter Valley NCIG Port 15 Hunter Valley Rail 92 95 110 Gladstone Rail 60 61 64 Dalrymple Bay / Hay Point Hay Point Port 40 40 42 Dalrymple Bay / Hay Point DBCT Port 66 72 85 Dalrymple Bay / Hay Point Rail 93 114 125 Abbot Point Abbot Point

Port 19 21 21

Abbot Point Rail 15 17 19 Source: Xstrata Coal

329. The expansion of the Dawson mine, owned by Moura Joint Venture and operated by

Anglo Coal, was completed in 2008 and Anglo Coal’s Lake Lindsay metallurgical coal project began dragline operations in January 2009.

South Africa

330. The 6.6 million tonne per annum Anglo Inyosi Coal Zondagsfontein project is expected to commence production during the second half of 2009 and is on track to deliver 6.6million tonnes/year to Eskom from 2010.

331. Anglo’s Macwest is expected to reach its annual production rate of 2.7million tonnes/year early in 2009.

332. The BHP Billiton US$1.4Bn investment in its Klipspruit and Douglas-Middelburg collieries are expected to be complete in 2009 and 2010 respectively, when the collieries will produce about 27Mtpa saleable thermal coal.

333. Xstrata and African Rainbow Minerals continued to invest R3.2Bn in their Goedgevonden

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colliery. When complete in 2009 the colliery will produce 6.7Mtpa saleable thermal coal

334. Richard’s Bay Coal Terminal continued with its R1.2Bn Phase V expansion to 91Mtpa and is due to be complete H2 2009. Transnet Freight Rail carried 62 million tonnes in 2008.

335. Early in 2008 the country experienced electricity supply interruptions as load shedding was implemented to manage an energy shortage. The power system had been vulnerable due to an inadequate reserve margin and coal stocks were low at the power stations. Poor quality coal, lower than expected production and logistical issues were exacerbated by unusually heavy rainfall in January and February 2008.

336. In response to this, Eskom initiated a recovery programme. The reserve margin has moved from around 5% in January 2008 to about 14% in January 2009 (including electricity imports) as a result of technical recovery of the Eskom power system and a drop in demand. Coal stockpiles for the system were taken from an average of 12 days in January 2008 to 20 system days by winter 2008 and around 41 days in September 2009, with every power station now having stockpile levels above 20 days and power stations vulnerable to heavy rainfall having special stockpiles of coarse coal treated with chemicals to resist moisture.

337. High and escalating primary energy costs were the major driver for Eskom’s average tariff increases of 27.5% for the 2008/2009 financial year and an effective 24.08% interim tariff increase for the 2009/2010 financial year.

338. Eskom burnt 121 million tonnes of coal during the 2008/2009 financial year and it has been estimated that between 20 and 25 new coal mining projects are needed in the short to medium term to meet Eskom’s demand.

339. The economy will eventually recover from the current economic downturn and it has been projected that South Africa needs up to 40,000MW of additional generation capacity by 2025, while meeting financial sustainability and climate change imperatives. Between April 2005 and April 2009, 4,454 MW of generating capacity was commissioned and a further 6,184 MW will come on stream within the next 5 years. The estimated costs of the planned capital expansion up to March 2013 is R385 billion (nominal). Eskom estimates that its coal demand will grow to 200Mt by 2018 and an additional 48Mtpa must be replaced due to depletion of existing mines.

340. Eskom is re-commissioning three previously mothballed power stations (combined total of 3,800MW).

• All eight units at Camden (totalling1 520MW) have been re-commissioned.

• Two units (400 MW) at Grootvlei have been re-commissioned, with the remaining 800 MW scheduled for the 2009/2010 financial year.

• Two units (228 MW) at Komati have been re-commissioned, with the remaining 750 MW scheduled for the 2009/2010 financial year.

341. The company is building two open cycle gas turbine stations:

• Ankerlig at Atlantis near Cape Town, where nine units totalling 1,338 MW have been completed;

• Gourikwa at Mossel Bay, south of Port Elizabeth, where five units totalling 746 MW have been completed;

and is upgrading and refurbishing the Arnot power station (300MW by 2010).

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342. Construction of Medupi power station is well underway. This is a dry-cooled thermal base-load power station in Lephalale, Limpopo Province (six units totalling 4,764 MW to be commissioned between 2012 and 2015).

343. Construction of Kusile power station has commenced (six units totalling 4,800 MW to be commissioned between 2013 and 2016). This power station will be fitted with flue gas desulphurisation technology, given its location near Witbank, Mpumalanga Province. The environmental approvals for the power station also require that Kusile be “carbon capture ready”.

344. Long term coal supplies have been negotiated for these new coal-fired power stations and Eskom is presently in the process of obtaining competitive bids for the supply to two new potential coal-fired power stations.

345. Construction of the Ingula pumped storage power station near Ladysmith in KwaZulu-Natal (four units totalling 1 352MW during 2013) is also at an advanced stage.

346. Planning and approval processes have commenced for further coal-fired power stations, a 100 MW wind facility and concentrating solar plant. Planning for future nuclear power stations is still continuing, although Eskom’s Board decided at the beginning of 2009 that it could not proceed with the proposed investment due to the high costs involved.

Germany

347. According to the Deutsche Energie-Agentur (Dena), additional demand for new power stations is up to 42 GW (installed capacity), assuming a continuation of the German nuclear exit strategy up to 2020. BDEW, the energy federation, reports that a total of 64 plants with total installed capacity of 35.5 GW are scheduled to come on line in Germany between 2009 and 2018.

348. This includes coal-fired power stations with a capacity of 20.4 GW and 6 lignite stations with capacity of 3.95 GW. Seven of the coal stations (7.4 GW in total) are already under construction and will commission by 2012. For lignite, there are currently two new projects and a modernisation that should add 2.84 GW of installed capacity by 2012.

349. As of July 2009, 5.4 GW of planned coal-fired capacity had been abandoned. These projects include: Vattenfall’s 800 MW plant at Rummelsburg in Berlin, Düsseldorf’s Lausward with 400 MW, Evonik’s 750 MW Herne 5, RWE’s 1600 MW at Ensdorf, Stadtwerke’s Kiels 800 MW coal-fired unit and 4 further projects.

350. RWE will build a 450 MW integrated lignite (instead of coal) gasification plant at Goldenberg.

351. Grosskraftwerk Mannheim AG (GKM) received approval for their 911 MW coal-fired block 9 in July 2009 with planned commissioning in 2013.

352. The Vattenfall Europe plan to build a 1.6 GW coal-to-power plant in Hamburg-Moorburg is still pending, as tough environmental considerations have to be overcome.

353. The key risk to new coal-fired generation is the full auctioning of CO2 certificates for power generation in the 3rd

The Netherlands

trading period (2013 to 2020), which was decided by the EU in December 2008.

354. In the Netherlands, coal-fired plants may face delays as the Dutch Council of State has asked the European Court of Justice for interpretation of the EU rules on emissions of

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oxides of nitrogen and sulphur dioxide in cases involving licenses for three new coal-fired stations proposed by E.ON at Maasvlakte, Electrabel at Maasvlakte and RWE at Eemshaven. The issue is whether the licenses breach the 2010 limits laid out in EU Directive 2001/81/EC on national emission ceilings for certain atmospheric pollutants.

United Kingdom

355. The Government launched a competition in 2008 for bids to fit a 400 MWe gross, 300MW net, post-combustion capture plant to a supercritical power plant. There are currently no supercritical power plants in the UK. Three projects are in this competition; E.ON at Kingsnorth, RWE (believed to be Tilbury) and Scottish Power (believed to be Longannet).

356. Kingsnorth, Tilbury and Longannet are also named (with PowerFuel's project at Hatfield colliery) as possible recipients for funding from the European Energy Programme for Recovery EEPR.

357. E.ON has applied for consent to build 2 new 800MWe coal-fired units at Kingsnorth, near London. However, E.ON announced in early October 2009 that it expected to defer the investment decision for up to two to three years because the global recession had pushed back the need for new plant in the UK to around 2016. RWE has announced plans for 2x800MWe units on one site near London and 3x800MWe units in the North East, but has not yet made formal consent applications.

358. The consent decision on Kingsnorth took around two years as Government sought to identify a long-term policy on coal generation. In spring 2009, they announced that;

• they were keen that coal (with CCS) should form an important part of the future UK low carbon energy mix, underpinning security of supply whilst being consistent with the goal of greenhouse gas emission reduction;

• new coal-fired plants could only be consented if they featured some degree (around 25% of total plant capacity) of CCS demonstration when initially built, with an expectation that the plant would move to 'full' capture in a relatively short time-frame after that; and that

• Government would supply financial support for the CCS demonstration phase of up to four demonstration projects, including the winner of the Government 'competition' for a 300MWe net demonstration of post-combustion capture and three more projects potentially gathered into a cluster of large point-source CO2

emitters.

359. The Government is consulting stakeholders on the details of these policies in summer 2009 and plans to issue a formal response to the consultation during 2009. New power plant consents are unlikely to be granted before the conclusion of this review.

Russia

360. SUEK has been building a new coal terminal at Vanino port and the first part of the terminal started operating in December 2008. The terminal can handle vessels of up to 150,000 deadweight tonnes and has dedicated coal handling facilities including rail car tippers, de-freezing equipment, stackers and ship-loaders. The annual capacity of Vanino Bulk Terminal will be up to 12 million tonnes of coal and SUEK is targeting exports of 4 million tonnes through the terminal in 2009.

Turkey

361. The table below shows existing coal-fired electricity generating plant capacity and new projects. All new developments are by the private sector rather than by EUAS, the state-owned power station company, and many feature Fluidized Bed Combustion technology

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and use imported hard coal as well as domestic lignite.

Table 11 –Coal-fired Electricity Generating Plant in Turkey (June 2009)

Fuel Source Source Installed Capacity (MW)

Technology Owner

In Operation

Lignite Domestic 7761 Conventional State Lignite Domestic 320 FBC State

Total lignite 8081 Hard Coal Domestic 300 Conventional State Hard Coal Imported 1320 Conventional Private Sector

Total hard coal 1620 Hard Coal & Lignite Domestic & Imported 135 FBC Private Sector Asphaltite Domestic 135 FBC Private Sector

Total in operation 9971

Under Construction Lignite & Hard Coal Domestic & Imported 1360 Conventional Private Sector Hard Coal Imported 600 Conventional Private Sector

Total under construction 1960

With Production Licences Lignite Domestic 1878 FBC Private Sector Lignite Domestic 100 Conventional Private Sector

Total lignite 1978 Hard Coal & Methane Domestic 1150 FBC Private Sector Hard Coal Imported 1605 FBC Private Sector Hard Coal Imported 3750 Conventional Private Sector

Total hard coal 6505 Asphaltite Domestic 540 FBC Private Sector

Total with licences 9023 Source: www.edpk.org.tr

362. The 135MW power plants at Çan, commissioned in 2007, and Silopi, using indigenous asphaltite and commissioned in May 2009, both use fluidized bed combustion technology. These two power plants provide an important opportunity for EUAŞ to evaluate the burning characteristics of low quality indigenous lignites and asphaltites.

http://www.edpk.org.tr/�

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4.4 Developments in Clean Coal/Near Zero Emissions Technology 363. The following paragraphs detail some of the developments and initiatives taken during

the last year towards the goal of mitigating the effects of greenhouse gas emissions on climate change, including increasing the efficiency of coal-fired power generation and accelerating demonstration and deployment of Carbon Capture and Storage.

United States of America

364. In May 2009, Mitsubishi Heavy Industries Ltd. (MHI) and Southern company announced that they are collaborating with EPRI and other partners on a demonstration carbon capture plant to remove 100-150 kilo tonnes/year of CO2

Canada

per year at Alabama Power’s Plant Barry. The plant will use MHI’s solvent technology.

365. Projects under the $230 million ecoENERGY Technology Initiative announced in 2007 received funding in 2008. These public-private partnership projects focus on research, development, and the demonstration of clean energy technologies to accelerate the development and market readiness of technology solutions such as carbon capture and storage.

Australia

Global CCS Institute 366. On 16 April 2009 Prime Minister Kevin Rudd launched the GCCSI at the inaugural

meeting of the Institute’s foundation members. Funded by the Australian Federal Government, the GCCSI is charged with accelerating the worldwide development, deployment and implementation of carbon capture and storage (CCS) technologies. 15 governments and over 40 major companies and industry groups have become foundation members of the Institute, which has also moved quickly to develop links with the CSLF, the IEA, the IEAGHG and the CIAB.

367. GCCSI has commissioned reports22

• A Strategic Analysis of the Global Status of CCS – a 1 000 page stock-take of CCS progress, including projects, regulatory frameworks and R&D, that aimed to identify gaps in global CCS deployment. The study had identified a total of 275 CCS projects; of which 101 are of commercial scale, 62 are integrated CCS projects, and 7 of those 62 are active. The key areas that need to be addressed to expedite the remaining 55 projects are storage (better site-specific data and clarity on regulatory liabilities), the business case (securing finance for demonstration to bridge the gap to commercialisation) and public acceptability.

covering:

• Portfolio of CCS Projects – identifying the ideal portfolio of CO2

• CCS Ready – to establish a clear definition of what it means to be “CCS-ready”

capture, transportation and storage projects to prioritise GCCSI spending.

National CCS Flagship Program

368. Following the Federal Government’s announcement of the A$2.4 billion Clean Energy Initiative Resources Minister Ferguson has called for nominations to support a number of carbon capture and storage (CCS) Flagship projects from the state governments and the

22 For further details see http://www.globalccsinstitute.com/work_plan/gccsi_work_plan.html

http://www.globalccsinstitute.com/work_plan/gccsi_work_plan.html�

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Chair of the Australian Coal Association Low Emission Technology (ACALET) (governing body of the COAL 21 Fund).

369. Nominated projects will be reviewed by an independent assessment panel with a view to announcing a project short list by the end of September / October 2009. Short listed projects will undergo a scoping study prior to final decision and announcement of projects to be funded in 2010. The Queensland government and ACALET have submitted joint nominations for Queensland projects while the New South Wales Government and ACALET have submitted separate but aligned submissions for projects in that state.

Project Updates 370. At present there are a range of proposed large scale demonstration projects in Australia.

The table below provides an overview of current projects (all Black Coal) under consideration.

Table 12 – Australian Large Scale CCS Demonstration Projects

Project Name Technology Location Proponents Status Zerogen IGCC + CCS Queensland Stanwell, MHI Pre-feasibility

Wandoan IGCC + CCS Queensland GE, Stanwell, Xstrata

Coal Pre-feasibility

Callide Oxyfuel Combustion

Queensland CS Energy, Xstrata Coal, IHI,

Execution

Schlumberger, Mitsui &Co, J-Power

Munmorah PCC New South Wales Delta electricity, CSIRO

Concept

Coolimba Capture ready Western Australia Aviva Corporation Feasibility

Japan

371. J-POWER’s new 600MW USC coal-fired power plant, the New Isogo Thermal #2, whose steam conditions are the highest (25MPa 600C/620C) in Japan, started commercial operation in July 2009.

372. In June 2009, the Ministry of Economy, Trade and Industry (METI) published a report on Japanese clean coal policies including the “Cool Gen Project” to develop clean coal technology (CCT) and the “Clean Coal for the Earth Project” to disseminate Japanese CCT to the world.

373. In July 2009, J-POWER and The Chugoku Electric Power Co., Inc. established “Osaki CoolGen Corporation” to construct and demonstrate a 170MW oxygen-blown IGCC plant employing EAGLE technology23 associated with CO2 capture. CoolGen is targeted to start operation in FY201624

374. CCS related R&D programs are:

.

• A pilot scale test of CO2

23 The “EAGLE Project”, an integrated coal gasification fuel cell system (IGFC), is a pilot-scale plant with an oxygen-blown 150 tonnes/day coal feed that was successfully tested by the New Energy and Industrial Technology Development Organization (NEDO) and J-POWER before March 2007. The EAGLE Project continues to operate from November 2008, capturing CO2.

capture from exhausted gas at the J-POWER Matsushima coal-fired power plant, employing high-performance Amine absorption, which was completed successfully (Mitsubishi Heavy Industries, 2005-2006).

24 http://www.jpower.co.jp/english/news_release/news/news090729.pdf

http://www.jpower.co.jp/english/news_release/news/news090729.pdf�

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• Demonstration of Oxy-fuel and CCS at the Callide coal-fired power plant, QLD, Australia as the first project under the Japan-Australia joint program (J-POWER, IHI Corporation and other participants). Construction started in November 2008 and the demonstration phase is expected to be from 2011 to 2015.

• Geological sequestration of 10,000 tonnes of CO2 into a saline aquifer (Research Institute of Innovative Technology for the Earth (RITE), 2000-2007) and CO2

• In May 2008 a CCS research company was established, funded by Japanese power, oil and engineering companies, to prepare for larger scale demonstration projects and researching expected CO

injection and enhanced coal mine methane recovery (Japan Coal Energy Center, 2002-2007). These were completed and the government is examining larger scale demonstration CCS projects; and

2

sequestration sites for demonstration.

South Africa

Underground Coal Gasification 375. Eskom Corporate Services Division (CSD) has funded a detailed research, development

and demonstration program that considers supplying Underground Coal Gasification (UCG) gas, obtained from the Majuba coalfield to Majuba Power Station. CSD is collaborating with UCG experts, Ergo Exergy Technologies Inc. (Canada), who have applied their knowledge gained from the former Soviet Union and Australian UCG operations.

376. Following extensive studies and test work that started in 2001, Eskom commissioned a UCG pilot plant and initially flared the UCG gas on 20 January 2007. This Majuba pilot plant is being developed in a phased manner, depending on the success of each previous phase. The pilot plant is the first step in a detailed feasibility study that will allow the technology to be developed for extracting energy from the presently un-minable Majuba coal resources, in one of the most environmentally acceptable means available.

377. A better understanding of the gasification process is evolving, and the nature of the gas produced is being evaluated. The project is now being advanced to implement the co-firing of the gas in a Majuba power station pulverised coal unit with piping, connections and burner modifications to Majuba unit 4 nearly complete. The control system integration is presently being finalised.

378. A revision to the original demonstration phase has been the inclusion of the firing of the UCG gas in a 40MWe open cycle gas turbine. The electricity generated will be used internally or fed into the national grid. This revision will provide the necessary confidence in this technology as an electricity generation option and allow for the correct specifications of larger generating units.

379. Eskom has completed preliminary studies that indicate very favourable energy costs for a 2,100 MWe UCG Integrated gasification Combined Cycle (IGCC) installation. The development of this high efficiency power generation option is presently being considered by Eskom and the National Energy Regulator, and an Environmental Impact Assessment is being conducted

South African Carbon Dioxide (CO2

380. As a joint project under the auspices of the local CSLF stakeholder forum, the Council for Geoscience (CGS) and the Petroleum Agency SA will publish the initial assessment of storage potential in a user friendly atlas by mid-1020. The atlas will illustrate the distribution and ranking of potential geological CO

) Storage Atlas

2 storage reservoirs in South Africa, including estimated CO2 storage capacities, the main emission sources, location of

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industrial hubs, transportation pipelines and other factors that may have a bearing on storage feasibility.

Centre for Carbon Capture and Storage 381. South Africa has established a Centre for Carbon Capture and Storage to address both

technical and human capacity building in CCS – leading to a demonstration plant in 2020.

European Union

382. The European Parliament and Council of Ministers have reached an informal accord on the European Energy Programme for Recovery (EERP), which will allocate €2350 million in EU funds to gas and electricity interconnection projects, €565m to offshore wind, €1050m to CCS and €15m to small island projects, all of which should reach investment stage during 2010.

383. The Commission sees the two sets of CCS financing - under the recovery package and the ETS mechanism - as completely different, non-exclusive funding streams, which means that receiving EEPR funds would neither prevent the same project claiming funds from ETS-allowances nor guarantee automatic allocation of ETS-based funding.

Germany

384. The draft law for CO2

• operators must provide proof that the complete containment of CO

capture, transport and permanent storage was delayed this summer and will now have to wait until after the national elections in September. It currently states that:

2

• responsibility for CO

in the storage is guaranteed for an unlimited period and make provisions against the risks to people and the environment; and that

2

storage is transferred from the operator to the federal state 30 years after closure of the storage facility.

385. Currently there are three CCS projects in Germany planned for commissioning by 2015. These include the Vattenfall lignite project at Jänschwälde (500 MW), RWE’s lignite project at Huerth (450 MW) and the E.ON coal project at Wilhelmshaven. The RWE and Vattenfall projects are seeking grants of up to €180 million from the European commission. RWE has tendered for the 450 MW integrated gasification combined cycle power station with CCS planned for Huerth, and the investment decision is set for Oct 2012.

386. E.ON’s plans for carbon storage and capture technology projects include:

Pilot projects for up to 10 megawatts in the first phase:

• Maasvlakte, Netherlands (running since 2008)

• Karlshamn, Sweden (due 2009)

• Datteln, Germany (due 2009)

• Staudinger, Germany (due 2009)

• Heyden, Germany (due 2010)

• A location in Germany yet to be decided (due 2010)

Commercial scale demonstration projects of more than 100 megawatts in the second phase after 2014:

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• Kingsnorth, UK - two 800MW units, with CCS initially fitted to 320MW and CO2

• Maasvlakte, near Rotterdam, Netherlands

stored offshore in a depleted gas field

• working with the Rotterdam Climate Initiative (RCI), to fit CCS to a new 1100MW unit added to an existing coal plant

• Wilhelmshaven, Germany 387. Vattenfall has started testing its new 30 MW CCS pilot plant, the first facility in the world

to use oxyfuel capture technology. The company plans for a larger 300-500 MW demonstration plant to be in full-scale operation by 2015. CO2 from both locations will be pumped into the depleted Altmark gas field.

The Netherlands

388. Currently three new build projects are on the European Union list for potentially receiving funds for CCS. These projects include are Nuon at Eemshaven (1300 MW with IGCC), E.ON at Maasvlakte (1050 MW pulverized coal) and Electrabel at Maasvlakte (800 MW pulverized coal).

Poland

389. Poland foresees a very active participation in CCS if it can be demonstrated to be fully safe technology that is feasible for widespread implementation. More than 50 companies, including Polish firms, have shown interest in building CCS installations. Some examples are:

• The Elektrownia Bełchatów power plant, part of the Polish Energy Group, is hoping for a subsidy from EU funds to build a CCS system. The company is building an installation along with an 858 MW lignite-fueled energy generation bloc.

• Zakłady Azotowe Kędzierzyn is also counting on some external support. The company intends to build, jointly with the Southern Energy Concern (PKE) - an energy group - an installation that will not only capture carbon dioxide but also allow it to be used for methanol production, for example. In its demonstration phase the project will generate enough synthesis gas to produce 500,000 tonnes of methanol a year, sufficient to meet the entire domestic demand for methanol and eliminate the need for imports.

390. However, industrial-scale application of CCS technology in Poland may be hampered by

the fact that, for the time being, the country has no laws regulating carbon dioxide storage underground.

Turkey

391. TKI is installing a pilot-scaled lignite gasification plant at one of its mines as a research project also involving consultancy from Turkish and American experts, Chicago Gas Technology Institute (GTI), Istanbul Technical University (ITU), METU and Gazi University.

392. TKI is developing a pilot-scaled Coal-and-Biomass-to-Liquid plant project in collaboration with TUBITAK Energy Institute, Electricity Power Resources Survey and Development Administration (EIEI), Marmara University and companies UMDE and HABAS.

393. TKI is a partner in an EU 7th Framework Programme project “ENERGY.2008.6.1.3: Efficiency Improvement of Oxygen-based combustion” being coordinated by CNRS-ICARE, France.

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5 CONCLUDING REMARKS 394. The information given in the body of this paper has been compiled with the help of CIAB

Associates and using some published sources. It describes developments over the last year in international coal markets and in environmental/energy policy in various countries from the perspective of individuals active in the coal, electricity and transport industries.

395. During the last year, the continuing focus of CIAB work has been on supporting the IEA Secretariat in the particular challenges for coal as it continues to play its role in world energy markets, bringing the expertise of CIAB Members and their Associates to the issues through meetings and workshops.

396. Of particular interest have been the adequacy of coal sector investment, key issues for world leaders as they move towards consensus on a post-2012 greenhouse gas emissions reduction agreement and bridging the commercial gap that may otherwise delay the introduction of large scale CCS demonstration projects.

397. Section 1 of this paper has summarised the high level messages derived from this work, while other sections have highlighted relevant developments in international coal markets, policy and investment to sustain the necessary role for coal in world energy supply and use.

CIAB, February 2010

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