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DECC coal price projections
October 2011
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DECC Coal Price Projections Introduction
1. This paper sets out some of the key considerations used by DECC in creating a set of price assumptions for the coal market over the next 20 years. For appraisal purposes DECC requires a low, central and high price scenario. Therefore, for each of the factors considered in this paper, a concluding assumption to use for each scenario is set out – these assumptions are partly based on judgement.
2. The paper was submitted to internal and external peer review and takes into account comments and suggestions made by academics, industry experts and government economists. Together with the analysis of the coal market fundamentals a rationale for analysing the link between coal and gas prices was considered, as this seems relevant for the UK. This is due to the fact the current energy and EUA markets appear to hedge fossil generation (from both gas and coal) quite well. However, coal markets are international in nature and although we note that coal and gas prices have moved closely together historically in Europe, we are careful not to imply any causal relationship. It is hard to rely on statistical relationships over long periods of time and, following peer review, we have looked at supplementing statistical estimates with production costs.
3. The projections are based on the analysis of fundamentals, mainly supply and demand, analysis of long run marginal costs, statistical analysis and interpolation. We have also sensed checked the figures against those carried out by external organisations. Given the difficulty of forecasting the future, the range of outcomes is wide. The projections should not be taken as a forecast.
4. Whilst there are a large number of factors to consider, this paper focuses on several key factors which influence the coal prices in the UK. We consider the role of Asian demand, gas prices, the correlation of gas and coal prices, market hedging strategies, future climate change policies and the role of new technologies.
Figure 1: Key Inter-linkages in Determining the Nature of Coal Prices
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5. The Coal market is international and UK coal prices follow international price movements. China and India are key players in the future evolution of coal prices and in the consideration of future scenarios. The balance between supply and demand within the global coal market is important. These factors are subject to considerable uncertainty and it is possible that the price risk is greater on the upside.
6. Long-run coal production costs are also important, as there is some evidence that the international steam coal market tends to be competitive1, and this view was also expressed by some peer reviewers. However, there is considerable uncertainty surrounding production costs for coal imported to the UK. These vary significantly between exporting countries.
7. There are key factors in the gas market that will also influence the coal price. These are in relation to liberalisation and gas contracting. These can indirectly affect coal prices due to substitution in the electricity generation market.
Background
8. The Figure below shows the historic pattern of coal prices in the UK in relation to gas prices. The UK market is liberalised and prices are determined by the cost of supplying the marginal unit of coal. The UK obtains the majority of its coal from imports from Russia, Colombia and South Africa. As can be seen below, UK prices fluctuate over time and there are times when coal prices are higher than gas prices and vice versa. However, as a result of deregulation more competitive and interrelated markets are developing in electricity and natural gas. Because coal and gas are substitute fuels used in the production of electricity the price of coal would be affected by the price of gas and vice-versa.
1 Haftendorn et al (2010)
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Figure 2: comparison of gas and coal prices
9. The EU ETS might be expected to reduce risk for coal and gas fired generation. If the price of gas increases relative to coal, generators will increase output from coal-fired plants, but because that releases roughly twice as much CO2/MWhe as gas the demand for EUAs will rise and so will their price, making the cost of coal-fired generation rise in sympathy with the cost of gas-fired generation (see Annex 2). For existing generating companies these risks are largely self-hedged at least in the medium run. We would expect the EU ETS to continue to exist and liberalisation in energy markets to continue to deepen, so this relationship between gas and coal prices could be expected to be important in the future.
10. When reading this paper it is also worth noting that this focuses of potential long-term trends, not short-term price movements. In the short-run prices are set by short-run marginal costs and reflects short-term fluctuations in demand (which is also seasonal), supply outages, capacity constraints at different parts of the market, etc. The focus of this work is not on short-term price movements. We aim to provide a range of scenarios that capture the range of possible outcomes for European coal prices in the long-run.
Market Fundamentals
11. Data: Historically, coal markets have tended to be international in nature. There is data on the historic price of coal and the price futures. Recent forward gas and coal prices are more highly correlated than in the past for UK fuel prices into major generating stations.
12. A period of change: Coal reserves are high and potential reserve additions could provide supply for many years post 2030. However, in the short and medium run supply is
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restrained by port and rail capacity in major producing countries (Australia, Colombia, and Russia) and there is a continued reduction in exports from China. Investments in coal and export infrastructure will affect supply but there could be bottlenecks. According to the IEA (WEO 2010) recent investments include Australia. The Russian export infrastructure is due to expand. African supply levels are predicted to rise. However, China is now a net importer and this will have a big impact on coal supply in more distant periods in the future (its net position is highly uncertain for the future). Transport cost and capacity are important factors in the determination of coal prices. Coal is mainly transported by train on land and by ship internationally. An increase in land transport costs such as the possible privatisation of parts of the rail infrastructure in Russia will have an impact on the international price. Shipping distances, and hence costs, could also increase prices.
13. In the long run: In addition to the factors mentioned, supernormal profits could attract new investment and mergers and acquisitions with the possibility of higher concentration. However, the availability of coal reserves would tend to make this a competitive market. Flue gas desulphurisation (FGD)2 and other pollution controls have reinforced the trend towards the commoditisation of coal. In the future, policies that constrain exports will restrict supply and increase prices in the long run. It is possible that countries may reduce exports and keep supplies for domestic consumption. Similarly, public opposition to the expansion of coal infrastructure would reduce investment and create capacity constraints.
14. The demand for coal: According to some estimates, global demand for electricity will drive growth in the demand for coal in the international market. The IEA (WEO 2010) estimates that, under the New Policies scenario (central scenario), the biggest growth in coal demand will be in non-OECD countries mainly from China and India, raising their share from 66% today to 82% by 2035. They also estimate that by 2035 demand from the OECD will account for less than one-fifth of global coal demand compared with one-third today, its coal demand declining on average 1.7% per year. Non-OECD countries account for all of the growth in global coal demand. Demand in power generation accounts for almost 60% of the increase in global coal demand while another 30% of the demand comes from the industry sector. The growth in non-OECD coal demand is projected to come from power generation with China, India and Indonesia responsible for 61%, 21% and 6% of the growth, respectively (see Figure 4.A in Annex 4).
2 FGD is a technology used to remove sulphur dioxide.
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Figure 3: Global Coal Demand in 2008 and 2035
Source: IEA, World Energy Outlook 2010
15. In addition, the single largest proportion of world-wide power generation comes from coal generation. High economic growth in Asia will expand demand and international trade. Severe economic slowdown, global backlash against globalisation and trade cooperation would reduce demand. Investment in coal-fired equipment will affect demand. Emerging nations building coal fired power stations are China, India, Chile, South Africa, Morocco and Argentina.
16. Coal Resources and reserves: Although it could be argued that coal reserves are widespread and are sufficient to meet demand for many decades, it is important to acknowledge the considerable uncertainties and limitations in the available data. The World Energy Council (WEC) estimates a downward trend in proved coal reserves. This could indicate that depletion is outpacing technological developments but it could also reflect a multitude of other factors such as land-use regulations restricting access to known reserves. Only six countries (USA, China, India, Russia, South Africa and Australia) account for 85% of global reserves, so future global coal supply hinges upon the supply situation for these countries. While each of these countries appears to have large reserves,
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some authors3 have highlighted how depletion and other factors could restrict supply of coal from these regions in the period up to 2050.
17. Chinese coal supplies are highly uncertain. In addition, China is already in the process of becoming a net coal importer owing to a combination of growing domestic demand, removal of export subsidies, the existence of export taxes, infrastructure constrains and the high cost of rail transport from the north which makes imported coal highly competitive in the centres in the south. Although observers agree on this trend, they vary widely in the anticipated volumes. An important factor is the sensitivity of global coal markets and coal prices to even relatively small changes in Chinese coal production and consumption trends. There is a risk that Chinese coal imports could be much higher than indicated by the WEO2010 that could translate into higher global and regional coal prices. Similarly, supply and demand projections for India and Indonesia remain equally uncertain.
18. The limit to continued growth in the use of coal does not come only from its scarcity but depends also on how coal’s carbon intensity can be reconciled with growing global momentum to stabilise green-house gas emissions at a sustainable level. The IEA estimates that coal production in most OECD regions is expected to decline over the period up to 2035 with the exception of Australia where growth in export demand increases by 0.6% per year. To meet growing electricity and industrial demand, China’s coal production is expected to grow by 1.1% per year in WEO 2010.
19. The impact of demand on the supply of coal: Uncertainties in the demand of coal may create lumpy investments and represent bottlenecks in supply due to capacity constraints. These factors are difficult to predict and will consequently be ignored in the consideration of coal prices in the period up to 2030 but could be important factors for particular years. Global coal consumption between 2000 and 2007 was driven primarily by the booming economies of India and China. Since China now accounts for 46% of global coal production and 47% of global coal consumption, the prospects for global prices are highly sensitive to the future of the Chinese economy in general and the Chinese coal market in particular. It is possible that the IEA and EIA scenarios underestimate the potential for future growth in Chinese coal demand. Around the year 2000 the energy use in the Chinese economy underwent a structural break. Since the year 2000, electricity consumption grew faster than GDP with an average income elasticity which is also higher than historically. The Chinese economy continues to expand at around 10% yearly and with the great majority of electricity coming from newly-built coal fired power stations, coal demand increased by 130% from 2000 to 2009.
20. Future Chinese demand will depend on the speed of growth of the economy, the rate of improvement in energy intensity and the fuel mix. Some authors (Shealy and Dorian 2010) believe that scenarios for Chinese coal could significantly exceed the IEA and EIA projections.
21. Other factors affecting the demand for coal in the long run: Climate change policies in regions other than Europe and technological developments will affect the demand for coal in the long-run. Technological factors are likely to play an important role but are very difficult to predict as they depend on a very complex set of factors. For example, the
3 Hook et al (2009) and Lin et al (2010)
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viability of Carbon Capture and Storage (CCS) technologies in the UK and globally could be an important factor, especially in the period after 2020. DECC’s estimates does not include carbon intensity as a factor influencing coal demand. Uncertainty remains regarding the long term prospect of low carbon generation technological developments. An increase in low-intensive generation technologies will affect coal prices negatively. Alternative uses of coal will also have an impact. For example, coal-to-liquid4 may show promise due to rising oil and gas prices. Currently only South Africa is undertaking these projects on a large scale. Policies that regulate (limit) air pollution will have a negative effect on the demand for coal. Similarly, government policies encouraging other generating technologies will limit the demand for coal.
22. Contractual arrangements such as the trend towards shorter-term and more flexible trading
away from long-term contracts will affect the price of coal.
23. Factors affecting the gas market will affect the coal market in the UK (see Annex 2). Coal and gas are substitute fuels used in the production of electricity so the price of coal will be affected by the price of gas and vice-versa.
Behaviour of Market Participants and Hedging of Risks
24. Rising oil and gas prices will make coal more competitive but, in the UK, this will also interact with the price of the EUAs. There is evidence that gas and coal prices are linked in recent years. For example, an increase in the price of gas will make coal more competitive but because generators would have to buy EUAs the cost of generation from coal would increase eroding its initial advantage. There is evidence that since 2007 coal and gas forward prices are more highly correlated thank in the past. Our analysis shows that the correlation between the actual cost of coal and the actual cost of gas generation in the period 2007-2010 is 72% when the appropriate EUA cost is added to each fuel (see annex for details).
Long Term Forecasts by External Organisation
25. Several other forecasts from external organisations were reviewed. These include the International Energy Agency (IEA), Wood Mackenzie, the US Energy Information Administration (EIA), the European Commission (EC) and Cambridge Econometrics (CE).
26. The IEA’s analysis gives different results depending on the scenario5. In the “450 scenario” coal becomes the only fossil fuel that has a reduction in demand, reaching a level almost 50% lower than under the reference scenario as there is a shift to cleaner fossil fuels. There is also a shift in Chinese power sector to less carbon-intensive activities and building
4 Converting coal to a liquid fuel (CTL) – a process referred to as coal liquefaction – allows coal to be utilised as an alternative to oil.
5 The WEO 20010 uses three key scenarios: A low carbon (450 ppm of C02) scenario, a “current policies” scenario representing the implementation of current national climate change policies and a “new policies” scenario that represents the implementation of broad policy commitments and plans announced by countries.
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of more efficient power stations. Also the production in exporting regions is lower, mainly due to lower demand in export markets and lower prices.
27. Some short-run cost curves for internationally traded steam coal derived from WEO are presented in Annex 1.
28. There is a big difference in costs versus the average FOB6 prices. Variations in FOB prices are related to stretched supply chains and infrastructure constraints affecting profit margins considerably. FOB prices in Asian markets have been rising in 2010 in response to a rise in demand from the Pacific markets.
29. The position of China as a net importer is uncertain and will have a big impact on the cost
of coal. It is difficult to overstate the importance of China’s role in global coal markets. China has struggled to keep up with rapidly rising demand. It is now working to overcome transportation bottlenecks and to speed up the development of its vast coal resources concentrated in the northern part of the country. China could become a net exporter and this is likely to have major implications for trade patterns and prices of internationally traded coal.
Liberalisation
30. Liberalisation in gas markets will impact on the price of coal in the UK and Europe more generally.
31. In addition, fuel prices may also respond to electricity prices. This makes the analysis even more complicated. The impact of electricity prices on fuel prices has been omitted in the analysis of price scenarios presented here for simplicity. This omission would be of concern when analysing the evolution of fuel prices in the very near term but would be of less relevance in the medium to long run.
Carbon Market and Coal Prices
32. Future developments in the pricing of CO2 and the future development of other carbon markets will have an important impact on the use of coal and subsequently on its price. The carbon price will affect the demand for coal. As coal produces twice as much CO2 as gas, the price will impact on the price of coal. In Europe, we expect the EU ETS cap to become tighter throughout the period and up to 2050 and this will increase the cost of electricity generation using coal. On the other hand, technological developments such as Carbon Capture and Storage (CCS) would also affect the coal market. Important uncertainties remain about the development of this technology but its impact will likely not be negligible.
6 Free on Board Prices, this is the price paid to take ownership of the commodity once onboard a shipping vessel in the exporting port.
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Analysis by External Organisations
33. Annex 1 presents the analysis of the long-run cost curves for internationally traded steam coal from the IEAs WEO. These do not on their own represent long-run marginal costs so should not be taken as an indication of a supply curve for coal.
34. Annex 2 sets out the arguments for some recent dynamic interrelations between coal and gas prices. The conclusions from this are:
• Given that coal is used as a fuel mainly in electricity generation and the demand for energy is likely to increase, there is a statistical relationship between the price of gas and the price of coal. Recent forward gas and coal prices are more highly correlated than the past fuel prices into major generating stations. Although this correlation is not extremely robust, it shows a degree of co-movement in gas and coal prices that cannot be ignored;
• The rationale for correlated prices in the UK and the European market will diminish over time if the substitutability of gas for coal in electricity generation falls.
35. Annex 3 presents the historical evolution of coal prices including the dramatic increase observed in 2008 and its subsequent decline, for reference.
36. A summary of the analysis by all external organisations reviewed is presented in Annex 4 including a qualitative description of the main drivers under each future scenario.
Surveying Forecasts by External Organisations
37. This approach involved surveying forecasts by external organisation and analysing the main underlying assumptions used in each one (see Annex 4 for details). All of the forecasts surveyed include figures up to 2030. The evolution of historical prices and a comparison of the forecasts by external organisations are presented in Figure 4.
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Figure 4: Coal Price Projections from External Organisations
Source: IEA WEO 2010, Wood Mackenzie, Cambridge Econometrics, European Commission (2009), EIA AEO 2010, Platts International Coal Report.
Methodology
38. In general, we use a combination of analysis of fundamentals together with estimates of LRMC constructed from SRMC and investment costs. We also use some statistical regression analysis based on the statistical link between coal and gas prices in the UK7 and analysis of forward prices judgement to derive the coal price figures for the period to 2030.
39. We use regression analysis to study the relationship between coal and gas prices8. Based on historical monthly figures for the period 1996-2010, we observe that fuel costs move closely together. There is a significant statistical correlation between coal and gas prices.
8 Regression analysis was also carried out for the cost of generation, including the carbon costs. We found that for the period 2007-2010 the correlation (R2) for coal on gas prices is 79% and the cost of coal generation (including carbon) Pc in £/MWhe is predicted to be Pc=0.73+12.13 Pg where Pg is the cost of gas generation in £/MWhe.
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The mathematical expression used is Pc= 0.29+79.71 Pg, where Pc is the price of coal and Pg is the price of gas, both in p/GJ9.
40. We recognise that a correlation coefficient (R2) of 49% is not very high and this is why we only use this relationship in conjunction with other techniques such as developing approximations to the long run marginal costs by using extraction and freight costs.
41. For the period 2013- 2020 we use a smooth linear interpolation. This is explained further in the next section. We also sense-check the figures for each scenario using a variety of different analytical methods and against the forecast of external organisations.
42. We provide an explanation of the methodologies used in each of the different scenarios in what follows.
Low Scenario
43. This scenario could come about as a result of timely investment, low economic growth, and liberalisation in Europe. It also represents low demand, high investment and high productivity worldwide.
44. In all scenarios, for the period 2011 to 2013, we based our projections on forward prices. The rationale behind this approach is that the market for futures accurately reflects the information about the developments over the next few years and that the years up to 2013 constitute a liquid horizon of forward trading. The near-term prices are exacerbated by a combination of factors, including export capacity restrictions, extreme weather, higher gas prices and German nuclear policy decisions.
45. The table below shows average forward coal prices (“API 2”, or “CIF ARA”) in the week commencing 11 April 2011.
9 We also carried out analysis of co integration between the coal and gas prices series on this regression. The time series of coal and gas prices are co integrated according to the Engle-Granger test. The residuals don’t have a unit root. Detailed analysis is included in the Annex 3.
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Figure 5: Coal Forward Prices
US$/tonne
2011 129.8
2012 130.5
2013 131.7
2014 133.5
2015 135.2
Source: Spectron, Weighted average of contracts for May, June, Q2, Q3 and Q4 delivery.
46. Based on this, we consider that in the central scenario, it would be reasonable to assume a constant price of U$S130/tonne from 2011 to 2013. In the low scenario, forward prices were adjusted downwards relative to $130/tonne by 5% and 10% in 2012 and 2013 respectively. This is a reflection that uncertainty increases further out along the forward curve, but also allows for smooth trends in the trajectory of fossil fuel price projections.
47. We lack solid empirical evidence of the degree to which coal forward prices are a good predictor of spot prices. The table below compares historical prices with the average price of the relevant forward contract in the last five days of December in the preceding year and in each of the two years before that. Based on the table below, recent forward prices (at one year ahead of delivery) have been within a +21% to -23% range of the corresponding spot price. Two years ahead of delivery, the range of uncertainty has been wider. However, our dataset is limited, and coincides with a major peak in global coal prices. Nevertheless, we still consider that an adjustment of near-term prices is needed (in the low and high scenarios) to reflect the availability of new information captured by the spot price that was not available at the time of the formation of future prices.
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Figure 6: Comparison of Historical Forward Prices and Realised Prices
Year Prices Forward contract (at year – 1)
% diff Forward contract (at year – 2)
% diff Forward contract (at year – 3)
% diff
2007 88.83 68.48 -22.9%
- N/A - N/A
2008 146.95 116.70 -20.6% 69.59 -52.6%
- N/A
2009 70.46 85.33 21.1% 103.41 46.8%
- N/A
2010 92.07 85.78 -6.8% 92.79 0.8% 92.66 0.6%
2011 (Q1) 123.18 120.14 -2.5% 98.74 -19.8% 98.75 -19.8%
Source: Platts, Spectron
48. From 2013 and 2020, we interpolate between the value of the 2013 forward coal price (minus 10%), and a price of $80/tonne in 2020. We believe the latter price to be consistent with LRMC in a low demand/ high investment scenario. We do not expect coal prices to fall very quickly, unless there is a sudden fall in power generation due to poor economic activity. In a scenario with low growth in demand, we do not expect prices to be above LRMC after 2020.
49. Annex 1 presents estimates of short-run supply costs for internationally-traded steam coal and estimates of seaborne freight costs. In order to come to a view on LRMC, these estimates were supplemented by estimates of capital costs and freight costs. There is uncertainty over how production and investment costs are likely to evolve going forward, so any assessment of LRMC in a low demand scenario relies on certain assumptions.
50. The main countries supplying the European market are Russia, Colombia, South Africa and the USA. According to peer reviewers from the Sussex Energy Group10, “…historically, the USA has been the ‘swing supplier’ to the Atlantic market, with higher cost Appalachian coal mines being the marginal supplier to the Western European market. Coal from the Powder River Basin in the US (i.e. Montana and Wyoming) is currently uncompetitive in the Atlantic market owing to the high cost of rail travel”. In recent years, South African coal has been increasingly drawn out of the European market and into the Asian market, due to the generally higher prices observed there11.
10 Steve Sorrell and Gordon Mackerron, Sussex Energy Group, March 2011, “Comments on the DECC paper:
‘Fossil fuel price assumptions - supporting paper on the coal market’”
11 Woodmac (2010)
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51. In a low demand/high investment scenario, we believe it is possible that US exports might no longer be supplied to Europe and the UK. Based on the estimates of short-run production costs and freight costs presented in Annex 1, Russia could be the marginal supplier, with short run costs (freight and production) of $71/tonne (in 2011 constant prices), compared to $57/tonne and $62/tonne in South Africa and Colombia, respectively.
52. To derive LRMC, we have to make some assumptions on the required margin over short-run costs, which will depend on the investment cost, cost of capital, required payback period and capacity utilisation. Investment costs vary by type of mine and required investment in additional inland transportation capacity. Based on Haftendorn et al (2010), citing IEA estimates, we assume investment costs of $50 per tonne of annual capacity addition for the value-added chain from production to the export terminal. We assume further a cost of capital of 10%12, a required payback period of 10 years and capacity utilisation of 90%. This gives a required margin of approximately $9/tonne of coal produced.
53. Based on this, we assume the LRMC in the low scenario will be $80/tonne ($71/tonne plus $9/tonne). In the absence of strong evidence to suggest otherwise, we hold this constant between 2020 and 2030. A combination of excess investment and improved productivity could offset the general trend of increasing extraction costs to keep the long-run marginal cost constant over the period. This results in a price that is below the majority of other forecasters but higher than the IEA 450 scenario by 2030.
54. In addition, the assumption of a 90% capacity utilisation might seem at odds with the assumption that Russia would also be the marginal import source in this scenario, but we use this simplifying assumption in order to arrive at a minimum margin estimate (a lower utilisation assumption would result in a higher required margin).
Figure 7: Low Price Scenario (US$/tonne, 2011 prices)
US$/tonne
2011 130
2013 117
2015 106
2020 80
2025 80
2030 80
12 Haftendorn et al (2010), uses estimates from New York University’s Stern Business School.
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55. As one sense-check, the price charged at Russian coal export points (the Free-on-Board, or “FOB” price) might give an alternative estimate of LRMC, as it might be argued that this price includes some element of margin. According to data presented by the IEA WEO 2010 (see Annex 1), the average FOB price for Russian coal exports was approximately $67/tonne over 2009 and the first half of 2010. Adjusting to 2011 prices and adding seaborne freight costs results in an estimate of LRMC (inclusive of seaborne freight) of approximately $83/tonne.
56. As an alternative sense-check, it is worth checking whether the resulting price trajectory might be enough to pay for any increase in investment required under a potential low demand scenario. Taking the IEA WEO 2010 “450 scenario”, demand is projected to increase to 2020 by 509Mtce (million tonnes of coal equivalent) on 2008 levels, before declining to 2030. Assuming short-run costs (plus freight) of $71/tonne, the “low scenario” prices calculated above and a discount rate of 10%, capacity built to meet the additional demand to 2020 could earn profits of approximately (NPV) $44billion. Even at investment costs per tonne of capacity addition of $85 per tonne of annual capacity addition, towards the higher end of the range estimated by Haftendorn et al (2010), investment could still be profitable.
Central Scenario
57. In the Central Scenario, for the period 2011 to 2013, our projections are informed by forward prices, as described in the section above, and are set equal to $130/tonne. As described above, we believe that the near-term prices are supported by a range of factors.
58. The coal price for the central scenario from 2013 and up to 2020 uses an interpolation between the assumed value of the forward price for 2013 ($130/tonne) and the coal price in 2020 that is informed by the statistical regression relationship described earlier (see Annex 3 for regression results). The assumed value of the price for 2020 is also informed on LRMC estimates.
59. The regression predicts a constant coal price of $106/tonne from 2020 to 2030. There are a large number of unknowns about the price after 2020. On the one hand, climate change action could reduce demand for coal and this will depress coal prices. On the other hand, new and more efficient coal plants could be built with the implication that the price of gas would have to fall relative to coal to compete. We recognise that this approach has some limitations in the sense that information available is based on current technologies whereas innovation is uncertain.
60. Given that the USA is generally the marginal supplier to the European market, the USA export price, plus freight costs, could be seen as a “ceiling” for European coal prices. Taking the US EIA AEO 2010 “reference case” projections, and adding freight costs (see Annex 1) results in a “ceiling” European import price of $115/tonne in 2030 (declining from a peak of $136/tonne in 2020).
61. It is also important to see how US marginal costs could evolve over time. Haftendorn et al (2010) use a global equilibrium model that predicts trade flows and allows for model-determined changes in production costs. Based on the “reference case” demand from IEA WEO 2008 (though subsequently the model revises demand downwards, due perhaps to price elasticity effects), the model predicts that the main suppliers to the European market
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will be Russia and the USA, with most of the Colombian and South African output going to Asian markets. Between Russia and the USA, USA Appalachian coal is predicted to be the most expensive in 2030; the price before inland transportation and seaborne freight costs are added is $68/tonne. Adding inland transportation costs ($26/tonne, see Baruya 2007) and seaborne freight costs ($21/tonne, see Annex 1), and ignoring any required margin for investment costs, results in a European import price of approximately $115/tonne in 2030. Haftendorn et al’s (2010) model itself predicts a European import price of $110/tonne in 2030.
62. Given the range of estimates above, we believe it is reasonable to round upwards from the regression-implied estimate of $106/tonne. Therefore, in the central scenario we assume that for 2020 up to 2030, the coal price is$110/tonne.
Figure 8: Central Price Scenario (US$/tonne, 2011 Prices)
US$/tonne
2011 130
2013 130
2015 124
2020 110
2025 110
2030 110
63. These estimates generally fall within the range of prices estimated by external forecasters.
64. As a sense-check, we looked at whether the prices could be sufficient to incentivise investment required to meet some plausible demand scenarios. Rough calculations show that, under some plausible marginal cost assumptions, the price trajectory above is sufficient to incentivise most new investment required to 2020 to meet the IEA “new policies” scenario, though it might not be enough for higher demand scenarios, such as the IEA “current policies” scenario.
High Scenario
65. This scenario could come about as a result of delayed investment, high economic growth, market power or strategic protection of prices by producers. It could also represent a world of high demand, low investment and low productivity worldwide.
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66. In the High Scenario for the period 2011 to 2013 prices are informed by forward prices. In the high scenario, forward prices were adjusted upwards relative to $130/tonne by 5% and 10% in 2012 and 2013 respectively. This is a reflection that uncertainty increases further out along the forward curve, but also allows for smooth trends in the trajectory of fossil fuel price projections (see “low scenario” above for more explanation of the use of forward prices).
67. The coal price for the high scenario case for the period 2013-2020 uses an interpolation of the adjusted forward price in 2013 ($143/tonne) and the price calculated for 2020 using the methodology described below.
68. We use the EIA AEO 2010 “high coal cost” scenario as a basis for a high price scenario from 2020 to 2030. In a supply constrained world with high demand for coal, much of the demand is likely to come from Asia, rather than Europe. In such a scenario, Asian countries may draw imports from Colombia and South Africa, in addition to traditional suppliers to the Asian Market (Australia and Indonesia). European imports are likely to come from Russia and the USA at a higher import price, with the USA likely to be the more expensive source. In such a scenario, it is possible that Europe will have to draw on some of the less productive mines in the USA. Hence, the EIA AEO 2010 “high coal cost” scenario, which is based on lower productivity growth rates, higher mining wages, higher transportation costs and higher mine equipment costs, could represent a reasonable “high case” for European import prices.
69. The EIA “high coal cost” scenario is not a smooth projection. We arrive at a smooth projection for European import prices by taking point estimates in 2020, 2025 and 2030; adding freight costs (see Annex 1) and interpolating between these points.
Figure 9: High Price Scenario (US$/tonne, 2011 prices)
US$/tonne
2011 130
2013 143
2015 146
2020 152
2025 155
2030 155
70. These projections are higher than predicted by any other organisation. However, given the evidence available, we believe that they represent a reasonable “high case” for coal prices.
71. Figure 11 and the table below present the DECC Fossil Fuel Price Projections for coal.
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Figure 10: DECC Coal Price Projections (US$/tonne, 2011 prices)
Low Central High
2010 93 93 93
2011 130 130 130
2012 124 130 137
2013 117 127 143
2014 112 124 144
2015 106 121 146
2016 101 119 147
2017 96 116 148
2018 91 113 149
2019 85 110 151
2020 80 110 152
2021 80 110 153
2022 80 110 153
2023 80 110 154
2024 80 110 154
2025 80 110 155
2026 80 110 155
2027 80 110 155
2028 80 110 155
2029 80 110 155
2030 80 110 155
Source: DECC
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Summary and Conclusion
72. This paper has reviewed the different drivers of coal prices: market fundamentals, the links between coal and gas prices, the influence of liberalisation in electricity and fuel markets, and the importance of the behaviour of market agents in hedging against price risks. A hybrid approach has been used to present coal prices projections based on the future evolution of gas prices and the analysis of constructed LRMCs. These projections have been compared with those forecasts of coal prices by external organisations (see figure 9).
73. There remain great uncertainties in relation to new technologies, climate change policies and uncertainties in the demand of coal, the trade position of China in the international market, etc. No explicit assumption about the nature or extent of future policies to combat climate change has been made nor the interactions with other factors.
74. All projections are based on the results from the analysis of market fundamentals, forward prices, the current tightness in coal markets, statistical analysis between existing coal and gas prices, analysis of long run marginal costs and the analysis of the international market. Although the statistical analysis reflects the current close substitutability of gas and coal as fuels used in electricity has its limitation and it therefore only used as a guide. So, further analysis of market forces and judgement was used to produce these projections
Figure 11: Comparison of DECC projections with external forecasters
Source: DECC analysis, Bloomberg Data
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Summary of Coal Price Assumptions
2011-2013 2013-2020 Post 2020 Sense Checked
Low Judgement based on a combination of the prevailing forward prices and a downward adjustment of 5% and 10% for 2012 and 2013 respectively
Assuming smoothed / linear interpolation
Estimate of LRMC for Russian coal
Against estimates of investment needed and forecasts by other organisations
Central Judgement based on a combination of the prevailing forward prices and
Assuming smoothed / linear interpolation
Statistical relationship, estimates of US export price
Against estimates of investment needed and forecasts by other organisations
High Judgement based on a combination of the prevailing forward prices and a upward adjustment of 5% and 10% for 2012 and 2013 respectively
Assuming smoothed / linear interpolation
US export price (EIA AEO 2010 “high coal cost” scenario)
Against forecasts by other organisations
Exchange Rates used:
$/£ = 1.546;
€/£ = 1.165
Coal-gas relationship
DECC analysis using a simple regression approach indicates that for the period 1996-2010 the price of coal Pc in p/GJ is predicted to be Pc= 0.29+79.71 Pg, where Pg is the price of gas in p/GJ.
23
References
Baruya, Paul (2007), Supply Costs for Internationally Traded Coal, IEA Clean Coal Centre, July 2007.
Energy Information Administration (2010), Annual Energy Outlook 2010: with projections to 2035.
European Commission (2009), EU Energy Trends to 2030: Update 2009, DG Energy.
Haftendorn, Clemens, Franziska Holz and Christian von Hirchhausen (2010), “COALMOD-WORLD: A model to assess international coal markets until 2030”, PESD Working Paper 96, September 2010.
Hook, M. Aleklett K. (2009), Historical trends in American coal production and a possible future outlook, International Journal of Coal Geology, UK Energy Research Centre: London.
International Energy Agency (2010), World Energy Outlook 2010.
Lin, B-q; Liu, J.-h, Estimating coal production peak trends of coal imports from China, Energy Policy, 2010, 38,512-19.
Mohammadi, Hassan (2009), Long-run relations and short-run dynamics among coal, natural gas and oil prices, Applied Economics, First published on: 29 May 2009, (free) downloadable online.
Mjelde, James W. and David A. Bessler (2009), Market integration among electricity markets and their major fuel source markets, Energy Economics, Volume 31, Issue 3, May, Pages 482-491.
Newbery, David, David Reiner, Tooraj Jamasb, Richard Steinberg, Flavio Toxvaerd and Pierre Noel (June 2009), Carbon Capture & Storage (CCS): Analysis of Incentives and Rules in a European Repeated Game Situation, DECC report, http://decc.gov.uk/en/content/cms/what_we_do/uk_supply/energy_mix/ccs/ccs/ccs.aspx
Shealy, M.; Dorian, J.P (2010), Growing Chinese Coal Use: Dramatic Resource and Environmental Implications, Energy Policy, 38, 3134-54.
Wood MacKenzie (2010), Pan-European Overview: Fuel Price Forecasts and Power Generation Economics.
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Annex 1: The Short Run Cost Curve for Internationally Traded Steam Coal
The WEO presents the costs of producing coal for the international market. Their analysis for 2008 and 2009 is presented below. It is interesting to compare the figures to see how much these costs can vary from one year to the next.
Figure A1.1: The Coal Supply Cash-cost Curve for Internationally traded Steam Coal
Source: IEA. World Energy Outlook 2009 (Fig 1.13)
However, in 2009 there appears to be little change in the average cash cost of internationally traded coal (Figure 1.B below). Based on this coal supply cash cost curve, the weighted average cost is around $42 per tonne across all countries. Please note the difference in costs versus the average FOB prices in 2009. The fall in FOB prices since the peak of 200, related to supply chains becoming stretched and infrastructure constraints, squeezed margins considerably. FOB prices in Asian markets are rising in 2010 in response to a rise in demand from Pacific markets. Coal futures suggests that prices will rise over the next four to five years as the global economy picks up. The highest prices could be found in Chinese ports.
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Figure A1.2: Coal Supply Cash-cost Curve for International Traded Steam Coal for 2009 and average FOB prices for 2009 and first half 2010
Source: IEA, World Energy Outlook 2010, Fig 5.5
Seaborne freight costs are cyclical, and are currently much lower than the highs reached in 2008. The table below shows average seaborne freight costs, adjusted for inflation, for steam coal into Rotterdam, a key North-West Europe coal hub, from 2004 to 2011. Without a more detailed analysis of the seaborne freight market, we use this average over the cycle as an approximation for long-run marginal cost for seaborne freight.
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Figure A1.3: Average Seaborne Freight Costs for Steam Coal (dry bulk) into North-West Europe (Rotterdam), 2004 to April 2011
Port of Origin US$/tonne, 2011 Prices
Puerto Bolivar, Colombia – Capesize 21
Puerto Bolivar, Colombia – Panamax 43
Richards Bay, South Africa – Capesize 21
Richards Bay, South Africa- Panamax 24
New South Wales, Australia – Capesize 38
Hampton Roads, Virginia, USA – Capesize 21
Hampton Roads Virginia, USA – Panamax 21
Murmansk, Russia to ARA - Panamax 15
Source: Bloomberg
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Annex 2: The rational for a Link Affecting Gas and Coal Prices
Gas and coal prices are linked in the short as well as in the long run. Because coal and gas are substitute fuels used in the production of electricity the price of coal would be affected by the price of gas and vice-versa. Indirectly, factors affecting the prices of gas will change the relative price of gas with respect to that of coal and will therefore affect its demand, in turn affecting the price of coal in absolute terms. Whilst coal is mainly used in electricity generation, gas is used for generation as well as to provide heating to households.
As a result of deregulation more competitive and interrelated markets are developing in the electricity and natural gas markets. Also, fuel prices may respond to electricity prices.
An additional important factor affecting the demand of these fossil fuels is the price of the EUAs. Coal and gas-fired generators face considerable risks trading in liberalised markets. The price of fuels, electricity and CO2 are volatile. Any generating company faces risks that depend on its technology as its variables cost depend on the type of fuel chosen and the cost of the EUAs while the price of spot electricity will depend on the marginal generator possibly burning a different fuel (and with different efficiency and other costs). If fuel and electricity prices do not move together, gross profits will be volatile and risky. The EU ETS might be expected to reduce risk for coal and gas fired generation. If the price of gas increases relative to coal, generators will increase output from coal-fired plants, but because that releases roughly twice as much CO2/ MWhe as gas the demand for EUAs will rise and so will their price, making the cost of coal-fired generation rise in sympathy with the cost of gas-fired generation (see Figure 2.A). For existing generating companies these risks are largely self-hedged at least in the medium run. In periods of high demand for electricity, generators would switch to coal, but because generating with coal produces more CO2 generators incur the cost additional cost of the EUAs. Newbery et al (2009) show that ETS makes both coal and gas competitive and this should have reduced the risks associated with selling electricity from both types of power plant between 2000 and 2008.
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Figure A2.1: UK Electricity Generation Choices
Source: Newbery et al (2009) from UK Quarterly Energy Prices
Each point in figure 2.A represents the cost of generation using gas in a 50% CCGT plant plotted against the cost of generating using coal in a 36% efficient station for various quarters. The triangles (red) represent the position before the EU ETS, the squares (black) are the costs of the fuels alone and the diamonds (blue) are the costs including the EUAs required for each fuel (twice as many for coal than gas).
The straight lines show the combination of gas and coal prices (with their associated EUA price) between which coal and gas plant would have been able to compete with each other on variable costs alone (depending on the efficiencies of each, where high efficiency of 55% can compete against low efficiency 34% coal at higher gas prices (as indicated in the dashed line). Note that the EUA price shifted the otherwise cheaper coal plant into this range of competition against gas. This is shown by the diamonds (blue) moving down and to the right compared with the squares. The EU ETS makes both coal and gas competitive, and this should have reduced the risks associated with selling electricity in both types of power plant.
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Figure A2.2: UK 2010 Forward prices of electricity and fuel costs excluding EUAs
Source: Bloomberg data processed
Figure A2.3: UK 2010 forward prices and generation costs (including EUAs)
Source: Bloomberg data processed, EEX for carbon prices
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Figure A2.4: Evolution of EUA Price
Source: EEX
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Annex 3: Coal Prices and Econometric Analysis
There are indications that we might be at the end of a price boom with prices likely to be lower in the near-term as the effects of the recession are played out.
In recent years, the price of seaborne coal into Europe has reached record levels, as much as twice the marginal cost of supply due to tightness on the supply-side. In late 2008, the coal market reached a turning point, with prices falling back towards the marginal cost of supply. The global economic recession was a major contributing factor in the change.
Figure A3.1 Comparison of Coal and Gas prices
Source: DECC analysis, Bloomberg data
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Regression results
Low Central High
2010 78.3 78.3 78.3
2011 98.7 98.7 98.3
2012 82.6 104.1 134.1
2013 65.4 109.4 132.0
2014 66.4 113.7 126.6
2015 66.4 112.7 125.6
2016 66.4 112.7 127.7
2017 67.5 109.4 128.8
2018 67.5 106.2 130.9
2019 68.6 106.2 133.1
2020 69.7 106.2 135.2
2021 70.7 106.2 137.4
2022 71.8 106.2 138.4
2023 72.9 106.2 138.4
2024 74.0 106.2 138.4
2025 75.0 106.2 138.4
2026 76.1 106.2 138.4
2027 77.2 106.2 138.4
2028 78.3 106.2 138.4
2029 78.3 106.2 138.4
2030 79.3 106.2 138.4
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Econometric Analysis
Analysis was undertaken to explore the possibility of cointegration between the series of coal and gas prices. The unit root test of Engle-Granger shows that coal and gas prices are cointegrated. Gas and coal prices do cointegrate, passing the test even at the 1% level of significance. This is shown by the Dickey-Fuller test on uhat having a test statistic of -3.266, lower than even the 1% critical value of -2.999.
The Dickey-Fuller tests on gas and coal prices suggest that both series are I(1) at 5% level of confidence.
Econometric test results are below, gas representing gas prices in real terms (2009=100) and coal are prices in real terms (2009=100). The Dickey-Fuller test for unit root on gas prices shows:
. dfuller gas Dickey-Fuller test for unit root Number of obs = 179 ---------- Interpolated Dickey-Fuller --------- Test 1% Critical 5% Critical 10% Critical Statistic Value Value Value ------------------------------------------------------------------------------ Z(t) -2.776 -3.484 -2.885 -2.575 ------------------------------------------------------------------------------ MacKinnon approximate p-value for Z(t) = 0.0618 . dfuller coal Dickey-Fuller test for unit root Number of obs = 179 ---------- Interpolated Dickey-Fuller --------- Test 1% Critical 5% Critical 10% Critical Statistic Value Value Value ------------------------------------------------------------------------------ Z(t) -0.677 -3.484 -2.885 -2.575 ------------------------------------------------------------------------------ MacKinnon approximate p-value for Z(t) = 0.8527 . reg coal gas Source | SS df MS Number of obs = 180 -------------+------------------------------ F( 1, 178) = 173.18 Model | 401290.365 1 401290.365 Prob > F = 0.0000 Residual | 412453.68 178 2317.1555 R-squared = 0.4931 -------------+------------------------------ Adj R-squared = 0.4903 Total | 813744.045 179 4546.05612 Root MSE = 48.137 ------------------------------------------------------------------------------ coal | Coef. Std. Err. t P>|t| [95% Conf. Interval] -------------+---------------------------------------------------------------- gas | .2920055 .0221891 13.16 0.000 .248218 .335793 _cons | 79.70859 7.404099 10.77 0.000 65.09748 94.3197 ------------------------------------------------------------------------------ . predict uhat, resid
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. dfuller uhat Dickey-Fuller test for unit root Number of obs = 179 ---------- Interpolated Dickey-Fuller --------- Test 1% Critical 5% Critical 10% Critical Statistic Value Value Value ------------------------------------------------------------------------------ Z(t) -3.156 -3.484 -2.885 -2.575 ------------------------------------------------------------------------------ MacKinnon approximate p-value for Z(t) = 0.0227Annex 4: External Forecasts Surveyed and Summary of the Main Underlying Assumptions
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Annex 4: External Forecasts Surveyed and Summary of Main Underlying Assumptions
Scenario Demand Supply
World GDP Growth / Energy Demand
Coal intensity of energy / GDP
Other
IEA WEO 2010 Current Policies Scenario (reference scenario)
World population growth assumed annual average rate of increase of about 1% and GDP growth by 3.2% per year on average between 2008-35.
No additional government action on energy – fossil fuels dominant source of primary energy – coal biggest increase.
China most of increase, most of rest of OECD demand decreases.
Rising oil and gas prices increase demand for coal.
Possibility of carbon price has negative impact on demand.
Government Policies are main source of uncertainty to 2035.
High reserves, potential reserve additions.
African supply increases.
Investment in transport and port facilities aids (slightly scaled back post 2008, then recovery).
IEA WEO 2010 New Policies Scenario
(same as above)
Additional measures are introduced that maintain the pace of global decline in carbon intensity established in 2008-20, in order to reach targets proposed by Copenhagen Accord.
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Scenario Demand Supply
World GDP Growth / Energy Demand
Coal intensity of energy / GDP
Other
IEA WEO 2010 – 450 scenario
(same as above)
Shift to cleaner fuels, increased efficiency in China
CCS viability factor after 2020
Lower production, due to lower demand.
EIA AEO 2010 – reference case
Baseline economic growth (2.4% / year from 2008 to 2035)
World oil price and technology assumptions
EIA AEO 2010 – high coal costs
Lower productivity growth rates, higher mining wages, higher transportation costs, higher mine equipment costs
European Commission
baseline price assumptions for the EU27 are the result of world energy modelling (using the PROMETHEUS stochastic world energy model) that derives price trajectories for oil, gas and coal under a conventional
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Scenario Demand Supply
World GDP Growth / Energy Demand
Coal intensity of energy / GDP
Other
wisdom view of the development of the world energy system
Wood Mackenzie
Near term: slow growth in demand.
Longer-term: Asian demand
Longer term: competition in Europe from gas generation tends to lower demand; US gas price increases tend to increase demand
Mid-term: Weakening dollar leads to cost increases
Long-term: Russian and Colombian capacity expansions; mining cost escalations
Cambridge Econometrics
Assumed 1% annual increase in prices, from 2010.
In general, UK prices are assumed to move in line with international prices, which also drive UK fuel import prices.
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International Energy Agency (IEA)
Price assumptions reflect the IEA judgments of the prices that will be needed to stimulate sufficient investment in supply to meet projected demand. OECD coal prices in the International Energy Agency: World Energy Outlook (2010) are determined by five broad factors:
Demand
• Oil and gas prices
• The carbon price
Supply
• Coal exports
• Trade position of China (net importer or exporter)
• Investments
Current Policies Scenario (Reference scenario)
Demand
• Fossil fuels remain the dominant source of primary energy and coal will see the biggest increase.
• The main driver will be inexorable growth in energy needs for power generation. Electricity demand is projected to grow at 2.5% per annum; over 80% of this growth will be in non-OECD countries (China and India in particular).
• Rising oil and gas prices will make coal increasingly more competitive.
• The possibility or the extension of a carbon price will negatively impact on coal demand.
Supply
• Coal reserves are high and potential reserve additions could supply demand growth for many years post 2030.
• Coal exports will continue to rise; recent investments in Australian coal infrastructure should ensure an end to bottlenecks witnessed in 2007 & 2008.
• African supply levels are predicted to rise. Although China will become a net importer rather than exporter.
• Recent (post 2008) scaling back of investment will slow the growth in production capacity but only to a relatively small degree and investment will pick up again when demand and prices recover.
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New Policies Scenario (central scenario)
World electricity demand is expected to continue to grow. Demand is projected to grow by 2.2% per year between 2008 and 2035, with more than 80% of the increase occurring in non-OECD countries.
Fossil fuels (coal and natural gas) remain dominant, but their share in total generation drops from 68% in 2008 to 55% in 2035. Nuclear and renewable resources expand.
Coal remains the leading source of electricity generation in 2035 although its share of electricity generation declines from 41% to 32%. A big increase in non-OECD coal-fired generation is partially offset by a fall in OECD countries.
Demand for coal increases by around 20% between 2008 and 2034 with almost all the growth before 2020. Coal demand grows by 0.6% per year and each sector’s share of demand remains roughly similar.
Cumulative investment to meet projected coal demand through to 2035 amounts to some $729 billion (in 2009 prices). Two thirds takes place in Non-OECD regions with China alone needing over $260 billion.
Global coal production grows from under 4900 mtce in 2008 to just above 5600 mtce in 2035. China accounts for half of global coal production by 2035.
The share of nuclear power in generation increases only marginally.
The share of renewables in global generation increases from 19% in 2008 to almost a thirst in 2035 (catching up with coal).
Figure A4.1 – Change in primary coal demand by sector and region in the New Policies Scenario, 2008-2035
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450 Scenario
• Coal becomes the only fossil fuel that has a reduction in demand, reaching a level almost 50% lower than under the reference scenario as a shift to cleaner fuels. This is due to the impact of policy action to cut demand.
• Coal demand peaks before 2020 returning to 2003 levels by 2035.
• Renewables and nuclear double their current share to 38% in the energy mix in 2035.
• Shift in Chinese power sector to less carbon-intensive activities and building of more efficient power stations.
• Production in exporting regions is lower, mainly due to lower demand in export markets and lower prices.
Figure A4.2: World Primary Coal Demand by Scenario
Source: IEA, WEO (2010)
Cambridge Econometrics
• In general; UK prices are assumed to move in line with international prices, which also
drive UK fuel import prices.
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Energy Information Administration
• Reference Case: Baseline economic growth (2.4% / year from 2008 to 2035, world oil price and technology assumptions
• High Coal Cost: Lower productivity growth rates, higher mining wages, higher transportation costs, higher mine equipment costs
European Commission
• The baseline price assumptions for the EU27 are the result of world energy modelling (using the PROMETHEUS stochastic world energy model) that derives price trajectories for oil, gas and coal under a conventional wisdom view of the development of the world energy system.
Wood Mackenzie
• Near term: Weak demand in the near-term due to effects of recession and competition from gas in the power sector
• Mid-term: Prices strengthen as dollar weakens, resulting in increased marginal costs of supply
• Long-term: Marginal costs increase in line with forecast mining cost escalation; prices supported by need to finance new supply resources; Increasing inter-fuel competition; South African supplies shift to Pacific basin, but Colombian and Russian expansions brought into play; German demand increases as domestic mining phased out and new coal-fired projects are completed; increase in prices 2020-24 related to increasing natural gas prices in the US – increases demand for Colombian coal; US continues to be swing supplier to the European market
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Figure A4.2: Coal Price Forecast – CIF ARA
Source: Pan-European Overview, Fuel Price Forecasts and Power Generation Economics, Wood Mackenzie, October 2010.
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