Category Archives: Cover Story

The Urgent Need to Move From CCS Research to Commercial Deployment

By Andrew Minchener
IEA Clean Coal Centre

Climate change is a serious issue that requires a global response. However, that response will not be a “one size fits all global solution”. Despite strident calls from some activists for a switch to renewables, with an immediate rejection of fossil fuels, the reality is that each nation will need to decide how it might move toward a lower carbon economy while deciding how best to balance the strategic energy trilemma. Compared to OECD countries, developing and industrializing nations will have different priorities, with a focus on ensuring that their populations have access to electricity, which can be the most effective means to improve both their education and standard of living through industrialization. In such cases, the fuel of choice is coal, being readily available, relatively low cost, and a proven choice for grid-based power generation.

That said, recognition grows that lowering carbon emissions, especially from coal, is both achievable and a valid near-term contribution to global greenhouse gas emissions reduction. In recent years, various critical advances have occurred in coal-based power generation technology, which can now achieve cycle efficiencies of some 45% (net, LHV basis), consistent with a 20% reduction in CO2 emissions compared to those from conventional coal-fired plants. Equally importantly, in China and Japan especially, various developments are being tested that are designed to achieve cycle efficiencies of some 50% within the next decade.1,2

Ultimately, to achieve “near-zero” CO2 emissions from coal-fired plants, it will be necessary to introduce carbon capture and storage (CCS), which comprises various options to capture CO2, then pressurize and transport it to a geological location for injection and permanent storage. This can include a depleted oil field where the injected CO2 will result in an increase in oil extraction with the majority of the CO2 remaining underground. This option, known as carbon capture, utilization, and storage (CCUS) will provide a revenue stream to offset some of the CO2 capture costs.

The Stern Review in the UK concluded that the cost to decarbonize the global economy would be significantly higher if CCS is not included for coal-fired power plants.3 Equally importantly, subsequent analysis has shown that the use of fossil fuels, particularly coal, for industrial applications such as iron/steel, cement, and chemicals cannot be replaced by renewable energy. However, these processes can be decarbonized through the introduction of CCS, which needs to be seen as a core part of the global climate response.


Research and development have delivered technology advances across capture, transport, and storage technologies. Such efforts will continue to be important to refine and improve CCS technologies, but the critical step must come through large-scale demonstration and deployment. In that regard, the limited number of operational plants and the relatively small scale of operation compared to commercial-scale units means that CCS is not yet having the impact required to significantly contribute to meeting global decarbonization targets (Table 1).

TABLE 1. List of operating and near-operational large-scale CCS projects4

Globally, 15 large-scale CCS projects are currently in operation, with a further five under construction and expected to start operations by 2017. These 20 projects represent a doubling since the start of this decade, while their total annual CO2 capture capacity will be close to 40 Mt once all are fully operational. Half of these are based on stripping CO2 through natural gas processing and, in all but two, using the CO2 for EOR. This approach is cost effective since removing CO2 from the natural gas, to ensure product quality specifications, will result in a revenue. In addition, there are six projects based on hydrogen, fertilizer, and synthetic natural gas production plants with CCS and EOR. More recently, this global portfolio includes a 115-MWe coal-fired power plant with CCS and EOR at Boundary Dam in Canada, and a 582-MWe unit with IGCC-based CO2 capture and EOR is just beginning operations at the Kemper County, Mississippi, facility. Shortly, these will be complemented with a 240-MWe unit at Petra Nova, Texas (Figure 1). Projects currently under construction will further diversify this portfolio, including the world’s first iron and steel CCS project in Abu Dhabi and a bioethanol plant in the U.S. This diversity indicates that CCS is a technology to limit carbon emissions from a wide range of power and industrial processes.

FIGURE 1. Three key coal power CCS demonstration projects (adapted from Carbon Brief5)

COP21 and the Need to Move Forward

The IEA produced a CCS roadmap suggesting the input required from CCS deployment as part of an initiative to limit the average global temperature rise to no more than 2°C (Figure 2).6

FIGURE 2. The IEA CCS roadmap consistent with limiting average global temperature rise to 2°C

This projection emphasized three goals that would need to be met, if the necessary CCS contribution toward carbon reduction through to 2050 is to be achieved:

  • Goal 1: By 2020, the capture of CO2 is successfully demonstrated in at least 30 projects across many sectors, including coal- and gas-fired power generation. This leads to over 50 MtCO2 stored each year
  • Goal 2: By 2030, CCS is routinely used to reduce emissions in power generation and industry, having been successfully demonstrated in industrial applications. This level of activity will lead to the annual storage of over 2000 Mt CO2.
  • Goal 3: By 2050, CCS is used routinely to reduce emissions from all applicable processes in power generation and industrial applications at sites around the world, with over 7000 Mt CO2 annually stored in the process

With hindsight, it is evident that the suggested timescale for large-scale deployment of the initial CCS techniques for use with coal-fired power generation and other industrial processes was overly optimistic, at least in making a significant start with CCS deployment. This is not because the techniques were technically unsuitable, but because there was insufficient attention given to establishing an enabling environment, taking into account the need for supporting policies, robust regulations, and an adequate financing model. The IEA projections suggested that there would need to be some 20 large-scale CCS projects in operation by 2020, capturing some 40 Mt of CO2 each year. In practice, while there is likely to be close to 20 projects, few will be coal based and the CO2 capture rate will be below 40 Mt/yr. More importantly, when the ramp-up of further projects is considered, the GCCSI database shows only a few additional projects close to operational status, which suggests a loss of momentum for several years.

Most of the projects that are not based on natural gas processing have included some level of capital grants from the host government. Although this is a reasonable expectation, given such demonstration projects are both strategic in nature and carry a level of risk, such funding sources can be politically fragile. To establish a large-scale commercial CCS plant will require a high capital investment because of the scale of operation. However, this issue should not prevent funding being obtained, provided an appropriate and stable incentive framework is in place. In many countries the lack of a coherent energy policy, wherein environmental issues are considered almost in isolation from security of energy supply and economic competitiveness, has discouraged funding and created reluctance for developers to take up opportunities because of uncertainties regarding long-term return on investment.

This is linked to an ill-conceived opposition to fossil fuels; many institutions are refusing to finance coal-fired power generation and other fossil fuel projects, which represent the most cost-effective means to reduce carbon emissions in the near-to-medium term. Not only does this make it more difficult for coal-based HELE (high-efficiency, low-emissions) technologies to be supported but it has the potential to impact on future CCS investment, as some institutions do not allow support for projects even with CCS.

In a “no CCS” scenario variant of the IEA Two Degree Scenario (2DS), assuming that the limitations of replacing coal or gas by expanding renewables use within a grid-based generation system can be overcome, without CCS, the transformation of the power sector will be US$3.5 trillion, or 138% more expensive.7

When the so-called ambition of achieving a decarbonization target consistent with an average global temperature rise of well below 2°C is considered, even more attention to CCS would be needed—and, at this stage in the technology development and deployment, it is hard to envisage how its input could possibly be ramped up.

The Possible Role of China to Drive CCS Forward

China has established significant capacity across the CCS chain through research and development, including the construction of nine pilot projects, and has benefited from extensive international cooperation. Consequently, it has reached an adequate level of readiness to take forward large-scale CCUS demonstration projects.

The National Development and Reform Commission (NDRC) of China and the Asian Development Bank (ADB) have worked closely together on several CCS/CCUS institutional capacity-building projects, which led to the creation of a coal-based CCUS development and deployment roadmap for China.8 This included the identification of a number of early opportunity demonstration projects based around large coal-to-chemicals plants in which CO2 capture is a low-cost (less than US$20/tonne) possibility. Many of its coal-to-chemicals plants are also in the vicinity of oil fields amenable to CO2-enhanced oil recovery (CO2-EOR). Thus, China has the unique opportunity to demonstrate CCUS at low cost, which would allow Chinese industry to gain familiarity in establishing major, multi-stakeholder projects, thereby building expertise on all aspects of the CCS/CCUS chain. These activities led to a declaration of intent by the Ministry of Finance of China at COP21 that the Chinese government will work with the ADB to establish several CCUS demonstration projects using this approach. This should also kick-start China’s intended overall CCUS demonstration and deployment program, which should position the nation as a global leader for ensuring that HELE clean coal technology will form a key part of a global low-carbon future.

The current low oil prices may have temporarily reduced incentives for CO2-EOR projects in China, but the fundamental drivers remain strong. Nonetheless, China imports more than half of its oil consumption while about 70% of its domestic oil production comes from nine large oil fields, which are all mature and are facing or will soon face a decline in production. In some of these oil fields, water flooding is no longer effective in maintaining oil production levels.8 Introducing CO2-EOR is thus inevitable to maintain the economic viability of such oil fields. To deploy CO2-EOR in these oil fields, it is essential to undertake early-stage pilot testing and demonstration. To overcome the lack of interest under the current oil prices, the government will need to incentivize industries to capture and transport CO2 and to conduct CO2-EOR.

The other factor that drives China’s intended CCS demonstration program is that “learning by doing” will subsequently drive down capital and operational costs. For example, engineers at the Boundary Dam coal-fired CCS project have announced that should they be required to design another CO2 capture unit, they could reduce the capital investment requirements by 30%. Equally importantly, in the future, rather than focusing on individual CO2 emitters, the costs of CO2 transport and storage, between 10 and 30% of the total CCS costs, could be significantly reduced by clustering power emitters together with industrial processes and using existing gas infrastructure. These industrial clusters could be linked to CO2 storage hubs via trunk pipeline networks and shipping routes. Again, China is well placed to adopt this approach in its industrial bases.


CCS can achieve significant decarbonization when applied to fossil fuel power generation technology, a wide range of industrial applications, and natural gas production. In particular, when applied to coal power technology, it can ensure developing countries and industrializing nations the low-carbon opportunity to maintain security of energy supply and economic competitiveness with low environmental impact of using coal. This will allow such nations to take the steps necessary to lift their people out of energy poverty and improve education prospects through access to electricity.

It seems inevitable that targeted support will be essential for CCS in the near term, and this will require innovative approaches that can achieve adequate financial support within a consistent policy and regulatory framework.

EOR can provide the foundation for future CO2 storage, by combining oil extraction with monitored CO2 storage to produce verifiable emissions reductions. EOR is expected to continue to act as a major driver for CCS since practices to promote increased CO2 utilization together with verified, permanent storage could deliver significant climate benefits.


  1. Feng, W. (2015, June). Cross component turbine generator unit with elevated and conventional turbine layouts. Presented at ASME 2016. ASME 2016 POWER & ENERGY Conference & Exhibition, Charlotte Convention Center, Charlotte, NC, U.S. Technical paper publication Power Energy 2016-59720. Available through:
  2. Makino, K. (2016). Clean coal technology—For the future utilization. In: G. Yue & S. Li (Eds.), Clean coal technology and sustainable development: Proceedings of the 8th International Symposium on Coal Combustion (pp. 3–9). New York: Springer. Available from:
  3. Stern, N. (2007). Stern Review: The economics of climate change. Executive summary,
  4. Global CCS Institute. (2015, October). The global status of CCS: 2015. Summary report,
  5. Carbon Brief. (2014, 7 October). Around the world in 22 carbon capture projects,
  6. International Energy Agency. (2013, June). Technology roadmap: Carbon capture and storage,
  7. Echevarria, J. (2016, 3 July). “No technical barriers” to deliver CCS in the UK. Energy Live News,
  8. Asian Development Bank. (2015, November). Roadmap for carbon capture and storage demonstration and deployment in the People’s Republic of China,

The author can be reached at


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The Role of Coal in the Energy Supply of the EU-28

By Hans-Wilhelm Schiffer
Executive Chair,
World Energy Resources,
World Energy Council

The European Union (EU-28) is one of the largest economies in the world, with a gross domestic product (GDP) of €14,635 billion in 2015. It has 508 million inhabitants, or 7% of the world´s population.1 Coal has played, and still plays, an important role in covering the energy needs of the EU-28. This article reflects on the role of coal within Europe in the past, at present, and in the future.


In 2015 the total primary energy consumption of the EU-28 was 2332 million tonnes of coal equivalent (Mtce).2 That ranks the EU as the third largest energy market worldwide—after China and the U.S. Table 1 gives the total primary energy consumption of the EU by energy sources in comparison with the global average energy mix.

TABLE 1. Primary energy consumption mix globally and in the EU-28 in 2015.
Source: BP Statistical Review of World Energy June 20162

A significant difference is the lower share of coal in primary energy consumption. In contrast, there is a higher contribution of nuclear energy in comparison to the global average. The share of non-hydro renewables, particularly wind and solar, in total primary consumption exceeds the global average by a factor of three.

The energy production within the EU-28 by energy sources in 2015 was:2

  • Oil: 103 Mtce
  • Natural gas: 155 Mtce
  • Coal: 208 Mtce
  • Nuclear energy: 278 Mtce
  • Hydro power: 109 Mtce
  • Other renewables: 194 Mtce

The share of production (including nuclear energy) in the total primary energy consumption was 45%. The energy import dependence of the EU was 55% accordingly.

Globally, the EU-28 has become the largest energy importer. The EU´s energy import was one-fourth the total worldwide trade in oil, gas, and coal. In contrast, the EU´s share in global primary energy consumption was only 12.4% in 2015. The import dependence in the case of oil and gas is particularly high, 88% and 70%, respectively. The share of imports in total coal consumption was 45%.3

The import dependence of the EU´s energy supply has increased over the last decade. The main reasons for this were the halving of EU oil and gas production and a decline in the production of coal by 17%. The trend of increasing import dependence would have been even stronger were it not for a doubling in the consumption of renewables.

The lack of diversification in the supply sources for oil and gas are concerning from an energy security point of view. Russia is the largest supplier of oil and gas imports. Four EU member-states procure their entire supply of natural gas exclusively from Russia: Estonia, Latvia, Lithuania, and Finland. The countries of Central and Eastern Europe, such as Poland, Czech Republic, Slovakia, and Hungary, cover between 50 and nearly 100% of their annual gas consumption via imports from Russia. Because some of the region´s gas comes via Ukraine, it risks transit disruptions due to Ukraine´s situation as well as Russia-related risks. This high dependence on a single supply source makes some EU countries susceptible to supply disruptions. Ten years after Russia cut off gas supplies to Ukraine and Europe in the winters of 2006 and 2009, and in the midst of the 2014 Ukraine crisis, concerns about a potential politically motivated disruption of gas supplies from Russia, and especially those that pass through Ukraine, triggered a discussion on creating an Energy Union to counter this threat.4

In fact, Russia is also the most important single supplier of coal. However, the supply options for coal are numerous, and thanks to the existing infrastructure, even the loss of the largest supplier could be offset with deliveries from other sources—unlike the situation for gas.


At the beginning of 2015, the EU Commission presented plans for a European Energy Union based on the strategic framework of the Commission and featuring five closely connected dimensions: energy supply security, solidarity, and trust; single energy market; energy efficiency; reduction of CO2 emissions from economic activities; research, innovation, and competitiveness. The Energy Union has the following specific objectives:

  • Energy dependency is to be reduced and investors are to be given planning security by the EU´s efforts to develop new sources, especially natural gas sources. Coal as a domestic energy source found in abundance in Europe is not mentioned specifically. The European Council wants to improve “the utilization of domestic sources”, however, and coal is one of these sources.
  • A strategy for the import of more liquefied natural gas (LNG) and for increasing energy efficiency is to be prepared with the aim of making the energy system “fit for a society low in carbon”.5

The prosperity and security of the EU depend on a stable and adequate supply of energy. Consequently, the Commission has developed a strategy for a secure European energy supply that fosters resilience against energy supply disruptions in the short term and reduces dependency on certain fuels, energy suppliers, and supply channels in the long term.

The energy mix of EU countries differs markedly, due not only to differing resources but also to the wide variety of national energy policies adopted over the years.6

Thus, power generation in France is based on nuclear energy. In contrast, Germany has decided to phase out nuclear energy by the end of 2022. As a result of political support in Germany, the share of renewables in total power generation reached 29.0% in 2015. This represents a fivefold increase since 2000. Hydropower has the highest share in power generation in Austria and in Sweden. Wind energy has a strong position in Denmark. In the Netherlands, gas is the most important energy source for power generation. Coal dominates power generation in Poland with a share of more than 80%. Of the UK´s electricity generation in 2015, coal accounted for 22.6 %—a decrease of 7.1 percentage points on 2014 due to plant closures and conversions. In 2015, the British Secretary for Energy and Climate Change proposed a consultation on the closure of all coal-fired power plants without CCS by 2025. A week later, the UK government cancelled its £1 billion funding of the flagship White Rose CCS project.7

Coal-fired power plant in Germany.


Figure 1 shows the total coal supply breakdown in 2015 for Europe. The total production of hard coal in the EU-28 was 100.3 Mt in 2015. Poland was the most important producer with 72.2 Mt, followed by the United Kingdom with 8.7 Mt, Czech Republic with 8.2 Mt, Germany with 6.7 Mt, Spain with 3.0 Mt, and Romania with 1.5 Mt. The total brown coal production in the EU-28 was 398.1 Mt in 2015. Germany is the most important producer of brown coal within the EU. The production of brown coal, classified as lignite, was 178.1 Mt in 2015. Other major producers of brown coal in the EU are Poland (63.1 Mt), Greece (45.4 Mt), the Czech Republic (38.1 Mt), Bulgaria (36.8 Mt), Romania (22.4 Mt), Hungary (9.2 Mt), Slovenia (3.2 Mt), and Slovakia (1.8 Mt).8

FIGURE 1. Coal supply in the EU-28 in 2015.

The coal supply of the EU-28 was supplemented by 191.6 Mt of hard coal imports (including anthracite) in 2015. In 2015, the most important such importers were Germany (55.5 Mt), the United Kingdom (27.1 Mt), Italy (19.5 Mt), Spain (19.0 Mt), France (14.3 Mt), the Netherlands (12.4 Mt), and Poland (8.2 Mt).8

Domestic production and consumption of coal has declined in the EU over the past two decades. However, domestic production of hard coal and lignite represent a significant share in total coal supply, 55% in 2015—after conversion of the different categories of coal into energy quantities using standardized heating values.

Imported coal can also be classified as secure in supply as the import sources are well diversified. Global coal reserves remain plentiful and are found around the world. On an energy basis, proven reserves of coal, essentially an inventory of what is currently economic to produce, are much greater than those of oil and gas combined, and are sufficient to supply more than 100 years of production at 2015 levels.9


The power and heat sector dominates coal demand in the EU, accounting for more than 75% of the total coal demand. Another 10% is used in blast furnaces and coke ovens for iron and steel production. Other industries, such as cement making, accounts for 9% of coal use, the residential sector for 3%, and commercial and other services for 1%. Coal demand has been declining slowly in all sectors.

Despite being the main source of coal demand, coal’s share in power generation in the EU-28 has decreased substantially since 2000, from roughly 32% in 2000 to 25% in 2015. Although the German nuclear phase-out temporarily led to some increases in coal’s contribution after 2011, the share of coal in total electricity generation was 42% in 2015 compared to 50% in 2000.

The share of coal in total power generation varies from country to country. The highest share of coal in power generation exists in Poland with more than 80%. In Germany, the Czech Republic, Greece, and Bulgaria coal is the most important fuel for power generation with shares between 40 and 50%. Indigenous lignite plays a major role in these countries. Coal covers 10–30% of power generation in the UK, Spain, Denmark, the Netherlands, Romania, Portugal, Hungary, Ireland, and Slovenia. Coal continues to make a major contribution to energy security in approximately half of the member countries.10


In recent years, sustainability—notably, mitigating climate change—has been the key driver for EU energy policies. However, concerns about energy security and industrial competitiveness have become more pressing in recent years.

Coal is one of the main pillars for power generation. “But the European Union does not have a specific coal policy, even though its policy affects coal use, including the European Union Emissions Trading Scheme (EU-ETS), air pollution directives and renewable energy targets. There is still substantial competitive indigenous coal production in the European Union and well diversified secure international coal supply at low (hard) coal prices; this fuel has clear security benefits. A continued contribution from coal in a low-carbon economy is however compromised by its high CO2 intensity. Considerable improvements in power plant efficiency and the use of carbon capture and storage (CCS) technologies will therefore be required.”11

Different European perspectives.

Over the last decade, the EU has embarked on three major actions in energy and climate policy: (1) the progressive liberalization of the internal energy market package, the so-called “Third Package”; (2) ambitious climate and energy targets and policy measures as part of the so-called “2020 Climate and Energy Package”; and (3) a new “2030 Climate and Energy Policy Framework” that prepared the EU position for international climate negotiations in 2015.

At their October 2014 European Council meeting, leaders from EU member-states reached an agreement on their ambitions for the 2030 Climate and Energy Policy Framework together with key conclusions on EU energy security:

  • A binding EU target of a domestic reduction in greenhouse gas emissions of at least 40% by 2030 compared with 1990—with reductions in the emissions-trading sector amounting to 43% and in non-ETS sectors to 30% by 2030 compared with 2005.
  • An EU-wide target of at least 27% for the share of renewable energy consumed in the EU in 2030.
  • An indicative target at EU level of at least 27% for improving energy efficiency in 2030 compared with projections of future energy consumption based on current criteria.

Energy security is also part of the 2030 Climate and Energy Policy Framework. In this context, the European Council recognized that the EU´s energy security can be increased by exploiting indigenous resources, as well as using safe and sustainable low-carbon technologies.

The EU-ETS remains the central instrument for reaching cost-effective emission reductions. In 2015, the EU-ETS was strengthened with the introduction of a market stability reserve and a steeper annual reduction in the number of ETS emission allowances issued: The 1.7% linear annual reduction will be raised to 2.2% from 2021.12


The World Energy Council (WEC) has prepared a study, World Energy Scenarios 2060. Presented at the World Energy Congress in October 2016, the paper comprises three scenarios. These scenarios, which are characterized in Table 2, are designed to help a range of stakeholders address the energy trilemma of achieving environmental sustainability, energy security, and energy equity.13

TABLE 2. WEC: Three scenarios and key attributes.
Source: World Energy Council. World Energy Scenarios 2060. London, October 2016

The three developed scenario stories are exploratory, not normative; they follow a bottom-up approach. They raise the following questions: Where do we stand today, and what are plausible ways that could lead us into the future? This is in contrast to other scenarios that work with a top-down approach, or roadmaps that ask how one gets from A to a defined target B.

The quantitative results are presented at the global level and by different world regions. For the EU-31 region (EU-28 plus Switzerland, Norway, and Iceland), a strong reduction in coal consumption is expected, in particular in the Unfinished Symphony scenario (see Figure 2). The share of coal in total primary energy supply will be 5% or even less in 2060.

FIGURE 2. WEC´s scenario results for Europe.

Coal’s share in EU´s electricity generation will diminish to approximately 2% in Modern Jazz and to 3% in Unfinished Symphony and in Hard Rock by 2060. Carbon capture and storage (CCS) is seen as a technology that will be implemented after 2030, in particular in the Unfinished Symphony scenario. In this scenario, 81% of electricity generated by coal within the EU-31 will use CCS by 2050, and this share is expected to grow to 95% in 2060.

The share of fossil fuels in the EU´s total power generation will be reduced to approximately 42% in Hard Rock, to 25% in Modern Jazz, and to only 16% in Unfinished Symphony by 2060. Renewable energies will contribute approximately 43% of the total electricity generation in 2060 in the Hard Rock scenario, 63% in Modern Jazz, and 67% in Unfinished Symphony. The remaining share will be covered by nuclear energy.


The use of coal in the EU has clear energy security benefits, given the low international coal prices and well-diversified supplies as well as EU indigenous production potential in lignite. The deployment of clean coal technologies, equipped with CCS, should be a priority to reduce CO2 emissions alongside the expansion of renewable energies and increasing energy efficiency. Furthermore, the total discounted mitigation costs for the long-term achievement of the 450 ppm CO2 eq. target would be 138% higher globally if CCS was not used.14 Thus, policy backing and a corresponding legal framework for the implementation of CCS in power generation (on the basis of coal, gas, and biomass) and in industry are necessary in order to secure investments that lead to a cost-efficient reduction of greenhouse gas emissions. Taking such a sensible framework into account, a stronger role for coal than anticipated in the WEC scenarios would be compatible also with the ambitious climate targets of the European Union.


  1. Eurostat.
  2. BP. (2016, 22 June). BP statistical review of world energy 2016,
  3. IEA Coal Industry Advisory Board. (2016). The role of coal for energy security in world regions. Regional/Country Chapters: EU-28, 2,
  4. Tagliapietra, S., & Zachmann, G. (2016). Rethinking the security of the European Union´s gas supply. Bruegel Policy Contribution, Issue 2016/01,
  5. European Commission. (2015, 18 November). State of the Energy Union 2015. COM/2015/0572 final. Available in various languages at:
  6. European Union (EU). (2012, 26 October). Treaty on the Functioning of the European Union. Official Journal of the European Union. Brussels, C 326/47-387. Available in various languages at:
  7. Zero Emission Resource Organisation. (n.d.). UK CCS cancellation,
  8. EURACOAL. (2016, May). EURACOAL Market report 2016 no. 1,
  9. Federal Institute for Geosciences and Natural Resources. (2015). Energy study 2015: Reserves, resources and availability of energy resources,
  10. International Energy Agency (IEA). (2016). Electricity information 2016. Paris: IEA.
  11. IEA. (2014). Energy policies of IEA countries – The European Union 2014 review,—the-european-union-2014-review.html
  12. European Council. (2014, 23 October). Conclusions on 2030 Climate and Energy Policy Framework,
  13. World Energy Council (WEC). (2016). World energy scenarios 2060,
  14. Intergovernmental Panel on Climate Change (IPCC). (2014). Climate Change 2014: Mitigation of Climate Change. Working Group III Contribution to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, 15, Table SPM.2,


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Digital, Interconnected Power Plants to Improve Efficiency and Reduce Emissions

By Jim Sutton
Senior Manager, GE Power Boiler Services
Peter Spinney
Product Manager, GE Power Digital

Countries around the world face a tremendous challenge in providing ample clean water, sustainable food supplies, and jobs to their citizens, while protecting the environment. Central to this challenge is managing and improving the power production infrastructure. Today, and for the foreseeable future, coal-fired power plants play a pivotal role by providing low-cost electricity to much of the world. Natural gas and renewables are growing in importance and are changing the ways in which traditional power plants operate. The rate of change in the electricity production business is unprecedented and is creating new opportunities for digital, interconnected, more intelligent power plants that are better able to meet these new requirements.

GE believes digital solutions will provide this intelligence, transform the industry, establish new business models, and create unprecedented opportunities to address global energy challenges. Over the next decade, the International Data Corporation has projected that approximately ˜US$1.3 trillion of value will be captured as part of this transformation.1 With software and data analytics, combined with advanced hardware, new digitally enhanced power generation will deliver greater reliability, affordability, and sustainability. This can help lower costs, improve efficiencies, create growth opportunities, and reduce CO2 output.

Advanced analytics can dramatically improve operations in coal-fired power plants by reducing fuel consumption, improving reliability, and reducing emissions. If deployed at every existing coal-fired power plant globally, this new equipment-agnostic technology, “Digital Power Plant for Steam” software, could eliminate 500 million metric tons of greenhouse gas emissions—the equivalent of removing 120 million cars from the road.2

GE’s smart technologies aim to improve efficiency and reduce the maintenance costs of coal-fired power plants.


Modern coal-fired power plants rely on a complex network of sensors, actuators, digital controllers, and supervisory computers to operate and coordinate each of the plant subsystems. Hundreds of feedback control systems serve to monitor plant processes and perform appropriate control actions, aiming to maintain optimum operating conditions regardless of system disturbances, such as changes in coal quality or electricity demand. However, the highly interactive nature of power plant parameters—where one parameter can affect many others—means that control is highly challenging, and plants are often not operated to their potential capabilities.

Power plants utilize a distributed control system (DCS)—an automated system that monitors and coordinates different parts of a power plant—to start and keep the plant running amid these changes. DCS is the most commonly used method of controlling the components in a modern plant, having replaced pneumatic, analog, and discrete controls.

DCS-enabled power plant controls perform quite well. Although advanced control is possible, most power plant DCS implementations use a basic scheme known as proportional-integral-derivative (PID) controller. A PID controller continuously calculates an error value, defined as the difference between a measured process variable and a desired set point. The controller attempts to minimize the error over time by adjusting a control variable—such as the position of a control valve, a damper, or the power supplied to a heating element—to a new value based on a mathematical algorithm. This PID control algorithm does not require information about the power plant operational process; it simply reacts to errors and adjusts the controlled elements to minimize errors over time.

Improved systems monitoring and analysis helps plants run more efficiently and with lower emissions.

The main disadvantage of this controls approach is that it is difficult to implement for the process of optimizing multiple variables. For example, a power plant operator may hope to reduce NOx and CO while improving heat rate and superheated steam temperature balance. To achieve this, DCS suppliers have included the provision for operators to “bias” the controls. In this way, basic controls continue to operate well, but power plant operators are able to use their knowledge of the process to fine-tune the controls to meet their operational goals.


GE envisions a more comprehensive analytic solution that builds on historic plant DCS and data historians to deliver improved outcomes for plant efficiency, low emissions, and reliable generation. In a recent GE survey of over 100 power generation executives, 94% of those surveyed believe that the internet and improved analytics will transform their industry in the coming years.3GE fully agrees and is developing both an overall web-based computer analysis environment (or enterprise tool), called PredixTM, and the individual applications that will provide the improvements. PredixTM is GE’s operating system for digital analytics for large machines that will manage data and supply tools to allow developers to easily create beneficial software applications. GE is now delivering many PredixTM applications. For the power industry, and coal-fired power plants in particular, some PredixTM applications are described briefly below.

Asset Performance Management (APM): A power plant consists of many assets, such as a boiler, a generator, a turbine, a boiler feed pump, or a coal pulverizer. Each asset has condition data that is already being measured and recorded. The goal of this application is to transform machine sensor data into actionable intelligence by combining robust analytics and domain expertise. This predictive information drives toward the ultimate goal of zero unplanned downtime and an optimal maintenance schedule.

Operations Optimization (OO): In any power plant, each of the plant assets must work together to accomplish the overall goal of efficient production at the system level. The goal of OO is overall improvement in client operations with performance visibility across power plant and fleetwide footprints, providing a holistic understanding of the operational decisions that can improve efficiencies, reduce emissions, expand capabilities, and lower production costs. Some of these optimizations can be performed immediately by local interfaces with the plant DCS.

Business Optimization: With the increase in complexity of maintaining a stable generating grid, many regions are requiring power producers to correctly forecast and price the power being produced. This is a challenge for the operations team, who may have limited tools. This application provides intelligent forecasting and portfolio optimization to enable trading and operations teams to make smart business decisions that reduce financial risk and maximize the profitability of the fleet.

Cyber Security: GE’s advanced defense system is designed to assess system gaps, detect vulnerabilities, and protect the customer’s critical infrastructure and controls in compliance with the various national-level cybersecurity regulations.

Advanced Controls/Edge Computing: This application allows plant operators to leverage data and analytics to manage grid stability, fuel variability, emissions, compliance, and other challenges that affect machine performance, as well as to execute fast starts and efficient cooldowns to meet dispatch and market demands. The ability to perform in this manner will be critical in a world that maximizes renewable power sources with their inherent variability.

PredixTM: As previously described, PredixTM as an overall platform allows application developers to safely and securely access plant information and build apps to improve any aspect of system performance. Predix is an open architecture that allows both GE and independent developers to use built-in analytic tools to quickly build the apps.

Predix Operational Optimization for BoilersTM is one of the many smart technologies being developed and offered by GE that could be useful for many coal-fired power plants and is explored in greater depth below.

Today, boiler modernization is focused on more than NOx reduction or heat rate. Goals are varied and the systems are asked to address a more diverse problem set. For example, boilers are challenged to control emissions, but also to deliver improved fuel efficiency and integrate complex air-staged combustion systems with different types of air quality control systems, such as complex combustion systems, selective catalytic reduction (SCR) systems, or selective non-catalytic reduction (SNCR) systems. Operating envelopes have expanded, intermittent renewables are increasing, and coal-fired power plants are being asked to ramp faster and also to ramp down to lower electricity output than ever before.

Predix Operational Optimization for BoilersTM is an analytic system that models how power plants respond to various inputs. Understanding how the interrelated systems interact allows a software solution to provide control biases—or set-points—to the DCS that improves performance. The software runs on a server at the power plant and communicates directly with the DCS. A coal power plant has multiple objectives: limiting plant emissions, achieving certain steam temperatures, while ensuring that the power plant operates as efficiently as possible. Predix Operational Optimization for BoilersTM understands multiple objectives and reacts much faster and more accurately than a human operator can because of the complex interactions and volume of data that must be assessed.

The basic configuration of the application is shown in Figure 1; the system builds models of power plant performance that predict what the plant’s state will be for the given set of inputs. As one example, the application is able to predict the likely values of the gaseous emission CO based upon current operating conditions. Predix Operational Optimization for BoilersTM can also model the impact of the various parameters on heat rate. With this understanding, the software issues optimal bias-to-set-point signals to the DCS that both improve plant heat and ensure that CO emissions do not exceed plant requirements. This is a considerable improvement over traditional plant controls that typically do not take CO into account or include heat rate as an explicit optimization target.

FIGURE 1. Predix Operational Optimization for BoilersTM processes data to simultaneously optimize control of various power plant operating parameters.

Fundamental to the operational improvements offered by the software is the ability to build mathematical relationships that model the process behavior. Fast, optimal adjustments can be made using an accurate predictive model of the boiler processes. Several types of models are used in the Predix Operational Optimization for BoilersTM system, as summarized in Table 1.

TABLE 1. Optimization and advanced control technologies used for boiler optimization


More than 120 installations of this boiler optimization technology have been installed and continue to be supported by GE on coal-fired boilers. Most of these clients are top utilities in the U.S., although there is now significant growth internationally. One example of a successful installation occurred at Calaveras Power, JK Spruce Station Unit Number 1, located near San Antonio, Texas. The unit is a 600-MW tangentially fired coal unit originally manufactured by GE in 1990. The OvationTM control system was manufactured by Emerson.

The results from the optimization are summarized in Table 2, where several key performance indicators (KPIs) are listed at full load conditions. The first two KPIs are heat rate and boiler efficiency. Heat rate measures how much heat input from the fuel is required to produce a kWh of electricity. A lower heat rate is better as it means less heat input (less fuel) is required to produce the same amount of electricity. Examining this KPI in the table in more detail, the next column lists the average heat rate achieved by the plant during periods where the optimizer was not running. The next column lists the average efficiency achieved with the optimizer turned on. As can be seen, with the optimizer turned on, the plant was able to achieve a lower net plant heat rate of 104 Btu/kWh, or a 1.08% improvement in heat rate. The second KPI focuses on the overall boiler efficiency, which looks at boiler performance separate from the overall plant performance.

The next two lines in Table 2 describe KPIs associated with gaseous emissions. Significant improvement was made in reducing NOx, a key objective of the optimizer. The average value of CO emissions increased somewhat but CO was reliably maintained below the target maximum value of 125 ppm. The next KPIs are related to the actual superheated and reheated steam produced by the boilers. With the neural net in operation the plant was able to get close to the ideal steam temperature for this plant, 1005°F, without exceeding it. Particularly important is the reduction in the need for reheat spray flows. Reheat spray flows deteriorate plant efficiency. This KPI was improved by 4.25%. Superheat spray flow was increased by 6.99 klb/hr, but this does not impact plant efficiency in the same way as reheat spray.

TABLE 2. Power plant improvements observed through implementation of smart optimization

Figure 2 shows how operation heat rate varies with the optimizer on versus off at several different loads. With the optimization software off (green), the heat rate is the highest, meaning the boiler was the least efficient. With the software on (blue) the heat rate was improved. As can be seen in the figure, improvement was made at all loads but the biggest gains were at high loads and low loads.

FIGURE 2. Optimizer on versus off at different loads

These results were achieved by maintaining proper fuel and air control, which is critical to achieving efficient combustion and cost-effective compliance with environmental regulation. Figure 3 shows how the software can improve efficiency while reducing NOx emissions by controlling the fuel/air ratio.

FIGURE 3. Predix Operational Optimization for BoilersTM helps power plants run in their optimal operating window.


The availability of digital solutions that optimize performance now allows GE to make more comprehensive upgrade offers that give greater value than solely providing the equipment. One example of this is low-NOx upgrades. Previously, GE had been limited to providing OEM low-NOx burner, SCR, and SNCR hardware as stand-alone packages with manual commissioning services. For low-NOx system upgrades, over 700 burner upgrade projects have been commissioned, and over 100 upgrade projects have been successfully implemented for post-combustion SCR and SNCR. With the robust closed-loop optimization system, it is now possible to offer full packages with SNCR and SCR that not only minimize NOX, but allow optimization of boiler heat rate, while minimizing the cost of sorbent needed in the SCR or SNCR.

The robust nature of the neural network software also allows GE to identify wear in key components, such as coal pulverizers. This ability to understand the condition and operating circumstance allows GE to offer more comprehensive multi-year service agreements that provide specified performance and reliability assurances.


Coal-fired power plants are an important part of the global infrastructure to produce electricity and face increasingly challenging operating requirements. In high-growth areas such as China and India, new high-efficiency coal plants are coming online. There is a real need to ensure that these plants, along with the massive installed base, operate with maximum efficiency and minimum emissions throughout their lifetime. Additionally, coal-fired power plants face the increasingly challenging generation mix that includes renewables. More renewables on the grid mean that power plants will need to ramp up and turn down as never before. Tighter emissions regulations also mean that more variables must be tightly controlled. Tomorrow’s smarter power plants can simultaneously address these multifaceted challenges with digital controls.


  1. International Data Corporation. (2015, May). Worldwide Internet of Things forecast, 2015–2020. IDC IOT M2M Report,
  2. EIA World Energy Outlook. (2015). EIA Carbon Emissions Factors published in Emissions of Greenhouse Gases in the United State, and US EPA Average Annual Emissions from Cars and Light trucks Fact Sheet 2016,
  3. GE Reports Staff. (2016, 19 January). GE Global innovation barometer 2016,

The authors can be reached at or


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Fueling Increased Electricity Production

By Paul Baruya
Supply, Transport, and Market Analyst,
IEA Clean Coal Centre

In the wake of COP21, as the world focuses on climate change mitigation, it can be easy to forget other important energy-sector considerations. For example, the emerging economies in Asia are eager to shake off the currency crisis of 1997 and build a robust and prosperous economic region. However, driving this growth requires more energy. There are many options for energy, and they will all play a role, but coal power is expected to be the principal contributor to increasing electricity production in many countries growing their electricity capacity.

According to the IEA, Asia’s energy demand is expected to grow by 80% between 2013 and 2035, driven by a tripling of the continent’s economy and a 25% rise in population.1 More investment in generation, transmission, and distribution is required.

Aside from the 150 GW of new coal capacity already under construction in India and China, coal-fired capacity in Southeast Asia—in the Association of Southeast Asian Nations (ASEAN)—will double between 2011 and 2020, to 80 GW, and then double again from 2020 to 2035, rising to 160 GW (see Figure 1). Furthermore, Asia is embracing the new paradigm of state-of-the-art high-efficiency, low-emissions (HELE) technologies, capable of burning coal with far less NOx, SOx, particulate matter, mercury, and CO2 emissions.

Baruya Figure 1

FIGURE 1. ASEAN electricity generation capacity1


Poverty is widespread among the non-OECD nations of Asia: 130 million people have no access to electricity in Southeast Asia,1 nor do 240 million in India,2 and although access in China is nearly complete, up to 200 million remain in poverty.3 Increasing capacity while maintaining affordable electricity is critical to individuals as well as to industry.

While renewables, nuclear, and oil are all used for power in the region, new capacity is largely based on renewables, coal, and natural gas. Thus, coal and natural gas are largely in competition for most baseload and load-following power generation throughout emerging Asia.

In 2015, the IEA Clean Coal Centre researched the cost of coal and natural gas power compared in different regions in Asia.4 By estimating the levelized cost of electricity (LCOE) for coal and combined-cycle gas turbines (CCGT), it was possible to determine which fuel is most likely to win the race to provide new capacity in Asian power markets. This article highlights the key findings from that study.


Fuel costs are one of the most important considerations when assessing power station economics. Historically, the price of coal is much lower than gas, even after adjusting for differences in energy content. For example, the average cost of natural gas in China in 2013 ranged between US$500 and US$700 per tonne of oil equivalent (toe), compared to coal, which was just US$160/toe. In ASEAN countries such as Indonesia, Malaysia, and Vietnam, however, domestic pipeline natural gas was less expensive than the average price of coal.

In addition to fuel costs, the LCOE cost per kilowatt hour is also determined by capital costs, which are impacted by the generating output of various plants (see Figure 2 for the average utilization rate of selected plants in China). Baseload plants such as coal, CCGT, nuclear, and geothermal generally recoup their higher capital costs much more quickly because they operate more hours per year.

Baruya Figure 2

FIGURE 2. Average plant utilization in China, 2000–20124

Large gas-fired CCGT plants are quick to build, taking only two years to construct in Asia, compared to four years for a coal plant. The cost of capital expenditure for CCGT plants is around half that of coal on a per kWe capacity basis, while in China and India some coal and gas projects cost almost the same (at about US$500–600/kW).



Coal-fired power plants in China now face some of the most stringent emissions limits in the world.

China is the world’s largest coal market, consuming 3900 Mt in 2014.4 LCOE analyses suggest that electricity generated via CCGT is twice as expensive as coal in China, almost entirely due to higher fuel costs (see Figure 3). While natural gas prices can vary, and can be as low as US$9/MMBtu for domestic gas, the cost of imported gas in 2013 was 3.5 times more expensive than coal on a per unit of energy basis. The prevailing gas price used was US$9–14/MMBtu, and would need to drop to about US$3/MMBtu to compete with a supercritical coal-fired power plant, and even lower for more advanced coal-based plants. Lower gas prices in the future are possible in China, but such price levels will not provide an economic incentive to develop sustainable and profitable supplies from LNG and unconventional sources such as shale/tight gas.

Baruya Figure 3

FIGURE 3. Average levelized cost of power for natural gas CCGT and various hard-coal technologies in China based on historic efficiencies and utilizations4

Despite the favorable economics, coal still faces some challenges in China. Three major zones, including Beijing and Shanghai, have moratoria on coal-fired plants in an effort to improve air quality. In such locations, natural gas plants dominate the power-generating fleet. Yet, China’s emission standards for coal plants are so stringent, a modern coal plant will be cleaner than any built in Europe—so metropolitan air quality would not be substantially affected by coal power, but rather by industrial facilities, municipal and residential boilers, and transportation. Pledges to reduce the role of coal in the power sector will slow growth, but considering the huge existing capacity and plants under construction today, it is unlikely that China’s reliance on coal-fired power will end soon.


India faces severe power shortages on a daily basis due to insufficient coal and gas supplies, made worse by large losses in the grid. Like China, India’s power generation is dominated by coal. By 2035, coal-fired power plant capacity could approach 900 GW if the country can overcome its various investment and environmental challenges. The nation’s natural gas reserves are offshore and production is in decline due to the maturity of the fields.

Gas prices in India vary depending on whether the gas is domestic or imported, and whether the supplier is state owned or not. India is the fourth largest importer of LNG, although LNG prices remain high (at least three times higher than that of coal on an energy basis).


Southeast Asian countries looking to increase natural gas consumption may need to rely on imported LNG due to
insufficient domestic resources and/or production.

India’s coal reserves are sited in the eastern half of the country; in 2013 production reached 600 Mt, while net imports from Australia and elsewhere grew to about 100 Mt/yr.5 Imported coal is priced at world levels while domestic coal is priced on a cost-plus basis, so prices are allowed to increase modestly with production costs. Coal remains relatively inexpensive (US$72/tonne at 2013 prices), but the coal production industry requires modernization and the rising need for coal washing of India’s low-rank coal will increase the cost in the future. Similarly, gas prices in the past have been low (US$4/MMBtu for domestic gas), but market reforms will lead to rising fuel prices across the board to attract private-sector investment to develop new fields and LNG import terminals with costs closer to US$14/MMBtu.

Unsurprisingly, analysis of LCOE showed that gas-fired power was marginally more expensive than coal in India, although the difference was not as stark as in the estimates for China. However, the lack of availability of natural gas, rather than costs, is probably the chief obstacle to gas power, and for this reason natural gas is unlikely to displace expansion of coal-fired power to any great extent.


In the past, much of the electricity in Southeast Asia has come from hydropower, natural gas, and oil. To date, the pace of demand growth for power has not matched supply, leading to regular load shedding. Variability and intermittency of renewable sources has led to a greater reliance on natural gas- and oil-fired power in some periods, with the economics of generation being complicated by fuel subsidies that have supported inefficient and higher emissions generation from oil.

Across Southeast Asia, HELE coal technology has generally emerged as the choice for future projects, offering a more resilient and affordable source of electricity to supplement inadequate gas and renewable power. In the background, oil is being actively discouraged in the generating sector where possible, yet remains an essential fuel in remote areas with little or no access to grid electricity.

Looking at past fuel prices in the region, along with project costs and plant performance, the LCOE comparison between natural gas and coal is mixed. The average LCOE in Indonesia, Malaysia, Vietnam, and Philippines suggests that current low natural gas prices make CCGT more competitive, where gas supplies are affordable and available (see Figure 4 for Indonesia as an example).

Baruya Figure 4

FIGURE 4. Average levelized cost of power for gas CCGT and various hard-coal technologies in Indonesia based on historic efficiencies and utilizations4

In Indonesia, the average LCOE for CCGT is around 7 US₵/kWh, while coal is closer to 8–9 US₵/kWh. In the case of Indonesia, however, the utilization of gas plants seems very low, which could possibly be due to the use of secondary fuels in the plants, meaning that the costs are often more closely based on those of an oil plant.

Evidence suggests that, natural gas-fired power plants have suffered from gas supply shortages, which have resulted in gas plants running at low utilization rates and turning to oil for backup. Indonesia has roughly three trillion cubic meters (tcm) of proven gas reserves and produces 90 bcm per year,6 but even greater potential lies in coalbed methane, with estimated reserves of 13 tcm, and the smaller resource of 1.3 tcm of shale gas. Without these unconventional resources being realized in Indonesia, it is unlikely conventional gas will serve both exports and future domestic demand from the country. The predicament posed by Indonesia’s gas supply problems is a common theme across the region, and will be faced by almost every major ASEAN economy.

Similar to India and China, the region does not have adequate domestic natural gas and thus is set to increasingly rely on higher cost imported LNG. Average and marginal gas prices must rise to make new gas supply sources economic.

By comparison, Indonesia’s coal reserves are substantial and resources are estimated at 120 Gt, although just 28 Gt are proven and recoverable.

Thus, in Indonesia, coal emerged as the fuel of choice for the government’s two Fast Track Programmes, accounting for 14 GWe out of the total 20 GWe that was due for completion by 2014. However, delays in finance and land acquisition are causing the program to lag behind schedule. Geothermal and hydropower are also important technologies to ensure progress toward a future with lower carbon emissions, but adopting HELE coal power will certainly limit the inevitable growth in CO2 emissions for the growing number of coal plants in the region. In 2014, the Ministry of Energy Minerals and Resources announced a target to add another 35 GW of new capacity, although the timeframe of this program could also be subject to delay. Nonetheless, by 2024 the state utility PLN expects 60% of the nation’s generation mix to come from coal, while 20% will be from gas and the remainder will be hydroelectric and geothermal renewables.


Reliable, affordable energy must serve as a foundation to achieve growth and development goals throughout ASEAN.

Most aspirations to build new coal plants throughout the ASEAN region are pegged on the availability of internationally traded coal, and many new power projects across the region are contracted to procure coal from Indonesia.

The story in other ASEAN countries is largely similar to that in Indonesia. While natural gas is cost competitive, resources, infrastructure, and/or production are insufficient to meet future (or even current) needs. In most places, LNG prices are too high to be economically competitive with coal. Thus, with either domestic coal reserves or relatively low-cost coal available for import, these countries are building coal plants to fuel their economies.

Malaysia, for example, has historically relied on natural gas for its power; today, gas accounts for 11 out of 30 GWe. Over time, declining gas production caused outages, forcing plant operators to switch to higher cost fuel oil and diesel. Since 2000, a building program for coal stations increased generating capacity by 7 GW, and by 2012 coal accounted for 41% of total generation.7

Similarly, to avoid becoming reliant on imported LNG, Vietnam is diversifying its power fleet, building 13 GW of new coal-fired plants, 3 GW of hydro plants, a range of smaller renewable stations, and just one CCGT plant. This new capacity is a large increase on the current generating fleet of 34 GW which is dominated by hydropower. Coal-fired plants will account for 75% of the total new capacity additions between now and 2020.8 Most of the new capacity comprises ultra-supercritical HELE coal technology specified for all but the smallest plants, a theme that will increase across the region.

The Philippines’ three natural gas CCGT plants are located in one province, and consume 94% of the country’s gas production. The LCOE of the gas CCGT fleet is slightly higher than that of the subcritical coal fleet, but the costs are broadly similar, generating at around 8 US₵/kWh. The country is currently self-sufficient in gas supply, but is expected to import LNG as domestic production has been stagnant. In early 2016, the President announced that more coal plants will be necessary to meet future baseload power, especially during dry periods that impact hydropower production.9


Natural gas and coal are largely in competition to fulfill new generation capacity in developing Asia. China’s huge fleet of coal-fired power plants is being retrofitted with emissions controls to meet strict emission standards and can be expected make a large contribution to the country’s power sector for decades, with the exception of some key urban areas where natural gas is being promoted by policies. India’s natural gas supply is insufficient to displace coal. The challenges faced by the coal production industry will mean there will be an increasing role for imported coal in the future.

In the past, Southeast Asian countries have been overly dependent on natural gas and renewables and, in some places, oil-based power; however, concerns over the future supply security and the ever growing demand cannot be met without a much more balanced portfolio of fuel types. Thus, coal capacity will be added in Southeast Asia, which is evident in most of the official power development programs in the region. Gas power is far from excluded in the strategies for Asian electricity developments, but rising natural gas prices due to the increase in LNG to supplement a shortage of domestic resources, which greatly impairs the competiveness of gas.

The shale oil/gas boom in the U.S. has yet to cause a major shift in Asian gas pricing, beyond its impact on the overall price of world oil supplies. LNG exports from the U.S. are limited to a few terminals, and are not sufficient to fill an increase in demand in developing Asia.

It is unclear how Asian coal and gas prices will be affected by developments resulting from COP21. More likely, a recovery in China’s economic growth rates will have more immediate impacts on regional energy prices. In any case, coal-based power will not be abandoned in Asia, especially as the fleet is young and the adoption of HELE technology will ensure it takes a lead in the affordable supply of electricity for many decades.

In essence, looking at LCOE, energy security, and current trends for the power fleet in emerging Asia showed that modern coal power was competitive, even against the high efficiencies offered by CCGT. In some countries gas was, and still is, cheaper; yet paradoxically official strategies suggest coal power is more attractive for future developments, often due to limited natural gas reserves and the expectation that imported LNG will be necessary to fuel new power plants. For the long term, there simply is not enough inexpensive gas in Asia to fuel the rapidly growing demand, and security of supply of future energy sources is taken seriously in Asia. Thus, coal will be the foundation of growth for baseload and load-following power generation in some of the world’s fastest growing markets.


  1. International Energy Agency (IEA). (2013). Southeast Asia energy outlook—World energy outlook special report. Paris: OECD/IEA.
  2. (2015). India energy outlook. Paris: OECD/IEA,
  3. Iaccino, L. (2014). China: More than 82 million people live below poverty line,
  4. IEA Clean Coal Centre. (2015). Coal and gas competition in power generation in Asia. London: IEA Clean Coal Centre,
  5. (2013). Energy statistics 2013. New Delhi: Ministry of Statistics and Programme Implementation,
  6. (2014). Handbook of energy & economic statistics of Indonesia 2013. Jakarta: Ministry of Energy and Mineral Resources,
  7. Suruhanjaya Tenaga (Energy Commission). (2014). Malaysia energy statistics handbook 2014,
  8. Bayar, T. (2016). Philippines needs more coal-fired power says president,

This article was based on “Coal and Gas Competition in Power Generation in Asia”, ISBN 978–92–9029–567-9, IEA Clean Coal Centre, Park House, 14 Northfields, London, SW18 1DD, UK, +44 (0)20 8877 6280. To download the full report, please visit or contact

To contact the author, please email


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Returning Mined Land to Productivity Through Reclamation

By Jason Hayes
Associate Director, American Coal Council
Editor-in-Chief, American Coal Magazine

Nearly 8.2 billion tonnes of coal were produced globally in 2014.1 Although a great deal of activity occurs around the extraction of coal, a limited amount of land is disturbed during mining compared to total landmass. For example, Natural Resources Canada has estimated that less than 0.01% of Canada’s total landmass was used in metal and mineral mining in over 100 years.2 Similarly, Haigh estimated that mining affected 0.16% of the U.S.landmass from 1940 to 1971.3 However, even if mining affects a relatively small amount of land, its impact can be significant and the extractive industries have an ethical and often legal obligation to return land to productivity.

Each coal mine has a limited life span due to the finite nature of the resource being extracted. Eventually the resource is exhausted, or the point is reached at which it is no longer profitable to extract for any number of reasons, such as increasing mine depth, increasing strip ratios, changing regulations, or market pressures.

When extractive activities cease, restoration processes must be completed, although they normally begin far sooner. In fact, reclamation processes typically begin while active mining is still occurring in another area of a mine. Thus, mining and restoration can be completed continuously and progressively throughout the life of a mine.

The costs associated with these restoration activities can be substantial: One estimate suggests US$1.5 million per mine, although varied mine sizes, regulatory regimes, or the presence of legacy reclamation costs could result in wide fluctuations in cost.4

Today in many parts of the world, reclamation and restoration plans must be prepared prior to mining. An improved understanding of the potential impacts of industrial activities, societal attitudes toward mining, increasingly stringent regulatory regimes, and dynamic market conditions now typically require companies to state clearly how their operating area will be restored before mining can begin.

There are various approaches to reclamation, and collaborative efforts between industry and government can help to improve mine management and reclamation processes. Thus, best practices and select case studies are worth exploring to highlight examples of successful mine closure and remediation.

A former opencast coal mine in Montana, U.S. now hosts grazing land. (AP Photo/Billings Gazette, Larry Mayer)

A former opencast coal mine in Montana, U.S. now hosts grazing land. (AP Photo/Billings Gazette, Larry Mayer)


Reclamation can be roughly defined as the replacement of soil materials—often to approximate original contour—and revegetation of mined areas or areas adjacent to mines that have been affected by mining activities. An alternative definition, offered by the International Energy Agency’s Clean Coal Centre, is “the process of repairing any negative effects of mining activities on the environment”. 4

Reclamation activities sometimes can also employ passive means of ecosystem restoration—wherein a less intensive management approach is taken and, for example, flora and fauna are allowed to self-colonize after soil replacement and stabilization are completed.5 However, the vast majority of contemporary reclamation and restoration efforts are based on technical reclamation, which exceeds simply repairing the affected property. Technical reclamation activities often aim to proactively manage a mined area for specific natural or recreational value, or other human uses, which can include infrastructure needs such as airports, schools, or shopping centers. Reclamation activities can also target agricultural or silvicultural (i.e., forestry) objectives. Plans to return mined areas to a more natural state, focusing on soil, vegetative, wildlife, and/or water management values, can also play a large role in guiding reclamation activities.

Both underground and opencast mines require reclamation, but the approaches are different. Reclamation activities for underground mines will typically require less aboveground activity, but can necessitate extensive management to avoid drainage and flooding issues after mine closure. This management can involve techniques such as filling of excavated areas with mine spoil or fly ash and diverting or controlling the flow of groundwater to keep it from entering existing mine structures. Doing so avoids the risk of rising water becoming contaminated by dissolved metals and other substances and potentially being discharged into rivers and streams. Notably, higher levels of calcite or carbonates in the rock, however, may neutralize acidic mine water, allowing metals to stay immobile.6

Reclamation of opencast mines typically involves replacement of overburden that was removed or repositioned to access buried coal layers. When excavated areas are built up, re-landscaping or recontouring is completed along with drainage control measures. Recontouring will be guided by mine plan objectives (i.e., the intended end use for the land). Where natural processes are sought, recontouring will typically attempt to return landforms to the mine site’s approximate original contour, or to mimic natural contours. Where other human uses are planned for, the land will often be leveled or shaped in a manner that improves access or aids in future infrastructure development.


The time frame extending from exploration to post-reclamation and closure requires decades (see Figure 1). In many cases, reclamation processes—which can include the mine closure and decommissioning stage, as well as the post-closure stage—can require as long as, or even longer than, the combined previous stages of exploration, site construction, and mining.

FIGURE 1. A mine project life cycle7

FIGURE 1. A mine project life cycle7

Even with mining plans in place, mining can substantially affect local or regional environments. Proper reclamation of mine sites, however, can avoid many risks, including unstable spoil piles, acid drainage and water quality issues, and potential cave-ins.

Best practice reclamation activities are designed to limit or avoid these impacts to the greatest degree possible. Although fully listing the legislative, regulatory, or best practices standards governing global mine reclamation is outside the scope of this article, a few prominent examples are worth highlighting. For example, general requirements for the approval of mining permits could resemble the conservation practice standards published by the Natural Resources Conservation Service (NRCS), U.S. Department of Agriculture (USDA). NRCS describes a threefold purpose for land reclamation:

  1. Prevent negative impacts to soil, water, and air resources in and near mined areas
  2. Restore the quality of soils to their pre-mining level
  3. Maintain or improve landscape visual and functional quality8

Australia’s Department of Industry Tourism and Resources gives similar guidance for land reclamation, but also encourages consultation, reporting, and monitoring with stakeholders during mine plan development and mining activities. Companies are also urged to rehabilitate progressively through the full life cycle of the mine and, where possible, to manage and rehabilitate historical disturbances.9 Expanded regulatory oversight combined with a trend toward a lesser number of larger, mechanized mining operations that are governed by binding mining plans are decreasing concerns about unregulated or unmonitored activities.


Employing best practices during contemporary mine reclamation helps to avoid the challenges associated with mines that were not properly reclaimed in the past. The varied nature of reporting measures and regulatory regimes governing mine management worldwide are compounded by the fact that many private or unregulated mines have been created, especially in developing nations where regulatory oversight may not yet be as thorough. Thus, it is difficult—if not impossible—to get a full count of the number of abandoned coal mines worldwide.

The legacy of abandoned mines, however, is being addressed in many areas. For example, since the passage of the 1977 Surface Mining Control and Reclamation Act (SMCRA) in the U.S., direct fees have been collected by government agencies from existing coal mining companies. Various states and Native American tribes have used over US$4.06 billion of those funds to reclaim almost “240,000 acres of hazardous high-priority coal-related problems”.10 As described by the UK Environment Agency (2008),6 similar programs are being carried out across the UK and internationally.


Collaborative efforts between mining companies and conservation organizations can promote successful mine reclamation as these organizations can lend expertise in developing best practices for wildlife, water, plant, and/or soil management. Demonstrating a transparent working relationship with conservation groups and other stakeholders can also help regulatory agencies when reviewing permit applications. If these agencies observe widespread support for mine plans and objectives and are convinced the area will be properly reclaimed and managed in the post-mining stages, permit approvals can likely be obtained much more easily.

One example of a collaborative effort is the U.S.-based Appalachian Wildlife Foundation’s Mine Land Stewardship Initiative (MLSI), which enables industry to pair with conservation organizations to move ahead in a challenging regulatory environment. The MLSI is working to design voluntary reclamation standards that “elevate the overall ecological performance of the coal industry”11 and help to enhance

  1. Conservation and restoration of ecosystem services
  2. Conservation and restoration of wildlife habitat
  3. Protection of water quality
  4. Recreational opportunities for mining communities
  5. Scientific and technical knowledge needed to protect and restore wildlife and aquatic habitats on mine lands11,12

Efforts like the MLSI are a positive and proactive approach to reduce confusion and litigation, increase stakeholder involvement and buy-in, improve transparency, and ensure the highest standard of reclamation is carried out.


Even with proactive management efforts like the MLSI, reclamation can be an expensive endeavor. As the mine will not continue producing saleable material, no additional income will be brought in after operations cease. Therefore, most regulatory agencies require some form of a financial safety net, or bonding, to ensure sufficient funds are available for reclamation even if a bankruptcy occurs. In this manner, company insolvency or an abandoned mine will not impose mine closure and reclamation costs on taxpayers.

While having adequate funds for reclamation is clearly important, public policy must recognize that environmental protection, reclamation in this case, must be balanced with financial realities to avoid stifling economic activity and to allow mining companies to operate profitably. The International Council on Mining and Metals (ICMM) has reported that expectations from an increasingly risk-averse public and government have been forcing assurance costs higher.13 The ICMM described how, in 1998, a mining company based in Australia had “identified more than 1,056 financial assurance instruments in place in four countries, which represents a contingent liability of greater than AUD$20 million. By 2004 the comparative amount had risen to AUD$60 million.”13 ICMM expressed concern that setting aside growing levels of operating funds in bonds restricts investment and operational flexibility. In fact, increasingly conservative expectations of certainty relating to environmental protection could place such strict financial and administrative pressures on mining companies that mining projects could be cancelled as uneconomic.

When this photo was taken in 2004, the Phoenix #2 mine had been backfilled. Final grading and seeding had yet to be completed on the top lift. Rock side drains were constructed at the perimeter to prevent erosion.

When this photo was taken in 2004, the Phoenix #2 mine had been backfilled. Final grading and seeding had yet to be completed on the top lift. Rock side drains were constructed at the perimeter to prevent erosion.


Numerous mines around the world are demonstrating successful reclamation projects, several of which are profiled in other articles in this issue of Cornerstone. One such project is Coal-Mac Mining’s Phoenix #2 surface mine in West Virginia, U.S. The Phoenix #2 mine was the recipient of the U.S. Office of Surface Mining’s 2010 Excellence in Reforestation Award for almost a decade’s worth of reclamation efforts and implementation of the Appalachian Regional Reforestation Initiative’s (ARRI) Forest Reclamation Approach (FRA).14

Ditches slow runoff and encourage groundwater recharge at Coal-Mac Mining’s Phoenix #2 mine.

Ditches slow runoff and encourage groundwater recharge at Coal-Mac Mining’s Phoenix #2 mine.

ARRI is a working group comprised of citizen representatives, industry, academia, and government, and was formed to encourage planting of productive trees on reclaimed coal mine lands and abandoned mine lands.15 FRA is a means by which mining companies and forest managers can improve forest productivity, wildlife habitat, floral diversity, and water management on reclaimed mine lands. The FRA is made up of five steps:

  1. Create a suitable rooting medium for good tree growth that is no less than four feet deep and comprised of topsoil, weathered sandstone, and/or the best available material.
  2. Loosely grade the topsoil or topsoil substitutes established in step one to create a non-compacted growth medium.
  3. Use ground covers that are compatible with growing trees.
  4. Plant two types of trees: (a) early succession species for wildlife and soil stability and (b) commercially valuable crop trees
  5. Use proper tree planting techniques
Phoenix #2 mine demonstrating new growth approaching year five (2009)

Phoenix #2 mine demonstrating new growth approaching year five (2009)

Phoenix #2 mine is a 560-acre (227-ha) operation, originally permitted in January 2001 under the approximate original contour (AOC)-plus backfill guidelines. Under these guidelines, final backfill elevations were established to mimic the natural terrain of West Virginia, avoid soil compaction, and enhance post-mine land use.

As year six approaches (2010), the Phoenix #2 mine area is returning to a productive, natural state.

As year six approaches (2010), the Phoenix #2 mine area is returning to a productive, natural state.


Finite resources entail a finite mining life cycle. As coal reserves in a mine are removed or become uneconomical to continue mining, reclamation activities will replace removed soil and/or substrate materials and revegetate the mine in an effort to (1) return it to as close to natural state as possible or (2) redesign landforms to allow improved human access to, or use of, an area.

Key objectives in reclamation activities are to reduce potential damage and prevent negative impacts to the natural environment in and near mined areas, to restore the viability and growing potential of soils to their pre-mining level, and to maintain or improve landscape visual and functional quality.

Reviewing effective examples of mine reclamation from around the globe, such as those profiled in this issue, allows the extractive industry to develop a suite of best practices for successfully reclaiming mined areas. These properly reclaimed mines can provide essential lessons on technology, policy, and collaboration and serve as the gold standard for mine reclamation efforts.


  1. BP. (2015). Statistical review,
  2. Natural Resources Canada. Minerals and Metals Sector. Resource Management Division. (1998). Background paper on land access, protected areas and sustainable development. Natural Resources Canada.
  3. Haigh, M.J. (Ed.). (2000). Reclaimed land: Erosion control, soils and ecology. Rotterdam: A.A. Balkema.
  4. Sloss, L. (2013, February). Coal mine site reclamation CCC/216. International Energy Association Clean Coal Centre,
  5. Krutka, H., & Li, L. (2013). Case studies of successfully reclaimed mining sites. Cornerstone, 1(2),
  6. UK Environment Agency. (2008). Science report—Abandoned mines and the water environment SC030136-41,
  7. International Council on Mining and Metals (ICMM). (2012). Mining’s contribution to sustainable development—An overview,
  8. Natural Resources Conservation Service. (2006). Conservation practice standard—Land reclamation, currently mined land,
  9. Australian Government, Department of Industry Tourism and Resources. (2006). Mine rehabilitation,
  10. Abandoned Mine Lands Portal. (2015). What’s being done,
  11. Ledford, D. (2012). Industry/conservation group cooperation: Promoting environmental and wildlife wellbeing. American Coal, 1, 30–34.
  12. Appalachian Wildlife Foundation. (2015). Mine Land Stewardship Initiative,
  13. ICMM. (2006, March). Guidance paper: Financial assurance for mine closure and reclamation,
  14. Angel, P., Burger, J., & Graves, D. (2006). The Appalachian Regional Reforestation Initiative and the Forestry Reclamation Approach,>
  15. Link, K. (2011). A dedication to West Virginia. American Coal, 2, 29.

The author can be reached at


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The Role of Business and Industry in COP21

By Nick Campbell
Former Chairman,
BusinessEurope Climate Change Working Group and International Chamber of
Commerce Climate Change Working Group
Chairman, European Fluorocarbon
Technical Committee
Co-Chairman, European Chemical
Industry Council Climate Change

Climate change has clearly become a major international issue. Stakeholders from around the world and from all sectors are now focused on how to minimize the impacts of climate change as the potential economic and development impacts are enormous.

There have been a number of international attempts over the years to tackle climate change. In the course of these negotiations, the way in which the world characterizes itself has changed from a binary one with developed and developing countries to one with developed countries, developing countries, and new emerging economies. The only international agreement on climate issues, the Kyoto Protocol, was created in the outdated binary world. It has proven to be insufficient—more needs to be done and by more nations. The next major opportunity lies ahead with the upcoming Conference of the Parties (COP) to be held in Paris in December. This meeting, COP21, is the culmination of years of work to build the foundation for an international agreement on climate.1

As the originators of a major proportion of greenhouse gas (GHG) emissions (the bulk of which is for products and services for society), business and industry are inextricably linked with the climate change issue. However, business is also the provider of solutions: the technology of the future and much of the finance to enable the transformation to a low-carbon economy. How business works with the climate change negotiation process, in particular COP21, and contributes to the most economically sound and efficient approach to transition to a low-carbon future are vital to successfully reaching an efficient, comprehensive global agreement on climate.


To be held 1–11 December 2015, COP21 is the culmination of the international climate negotiations since 2005 (see end of article for more information). The four years of discussions since the COP in Durban in 2011 have resulted in the development and adoption of a draft negotiating text, compiled at the February 2015 meeting in Geneva.2 This original 86-page text was revised at a negotiating meeting in Bonn in June. The co-chairs of the group responsible for the negotiations issued a new text on 24 July that will undergo further revision in two subsequent meetings (also in Bonn) from 31 August–4 September and 19–23 October. The goal of these later meetings is to streamline and drastically shorten the working text into a form that Ministers can use to reach a final deal in Paris.

For COP21 negotiations Parties have been grouped by development status. Green = Annex I and II Parties, Blue = Annex I Parties, Yellow = Non-annex Parties, Red = Observer states and organizations. Parties classified as Annex I include developed countries and economies in transition (EITs), Annex II countries are developed OECD members required to give financial and technical support to EITs and developing countries, non-annex countries are developing countries requiring support.

For COP21 negotiations Parties have been grouped by development status. Green = Annex I and II Parties, Blue = Annex I Parties, Yellow = Non-annex Parties, Red = Observer states and organizations. Parties classified as Annex I include developed countries and economies in transition (EITs), Annex II countries are developed OECD members required to give financial and technical support to EITs and developing countries, non-annex countries are developing countries requiring support.

A strong driver behind the work of the governments under UNFCCC has been the reports of the Intergovernmental Panel on Climate Change (IPCC). Its 5th Assessment, published in 2014, reported an increased certainty in anthropogenic impacts on climate and the need for concerted global action. While there has been much debate around the exact wording used by the IPCC (and, in fact, the role of IPCC in general), a clear message has evolved from the group: Climate change is real and action must be taken to both prevent and reduce its impacts.

COP21 provides the opportunity for governments to “walk the talk” and to demonstrate that they can work together to tackle the risks of climate change while protecting economic growth and development. National and regional actions are important, but collective action is vital. International collaboration can lead to enhanced action as well as avoid competitive market distortions that can result from nations taking actions unilaterally. The developed world has agreed that it must lead the way, but rapidly growing emerging economies must closely follow. Nothing less than a binding comprehensive global agreement in Paris will be sufficient.


There are three main challenges to finalizing an international deal at COP21: reaching agreement on emissions reductions, adaptation to the impacts of climate change (current and future), and the financing of actions. Going into the final Ministerial negotiating sessions, the negotiating text must be high level if a final agreement is to be reached. Many of the details will be developed in separate decisions, or processes will be initiated to develop modalities and procedures to allow future implementation (e.g., a process to develop rules for the use of market mechanisms to help compliance with emission reduction commitments).

One essential aspect that must be tackled in any agreement text drafted in Paris is related to reviewing progress and ratcheting up ambitions as the commitments agreed to in Paris are unlikely to be enough to meet the emission reduction goals as outlined by the IPCC.

The devil will be in the details. Extensive (and possibly extended) discussions on many topics will be necessary. A few of the most important topics and the key questions to be answered are listed in Table 1.



Business has a vital role in the fight against climate change. Many companies are affected by climate change and have already taken adaptation actions. For example, some power generators have planned for changes in cooling-water supplies. Business will provide the technologies that will enable society to move toward a low-carbon economy. Business will also provide much of the financing to enable adoption of existing and new technologies. Business will continue to innovate and develop new products for the future as well as improve current process and operating procedures to reduce energy consumption and improve efficiency. For example, carbon capture and storage, including utilization (CCS and CCUS), will play a vital role in a low-carbon future, especially in the least-cost approach to climate change mitigation.3

UN Secretary General Ban Ki-moon at COP20 in Lima, calling on the Parties to announce emission targets ahead of COP21. (AP Photo/Martin Mejia)

UN Secretary General Ban Ki-moon at COP20 in Lima, calling on the Parties to announce emission targets ahead of COP21. (AP Photo/Martin Mejia)

Business is expected to have a major role in providing investment to finance the transformation to a low-carbon economy through investment institutions and banks. How the use of markets for compliance will be permitted within the 2015 agreement will be instrumental in the provision of finance. The Clean Development Mechanism under the Kyoto Protocol provided a great incentive for business participation in developed and developing countries alike and generated thousands of emissions reduction projects. These projects involved both large and small companies and ranged from improved cook stoves to renewable facilities. Insurance companies will also play a major role in adaptation to climate change and risk assessments of future impacts.

However, creating the drivers for business to take these actions is a very real challenge. Transition to a low-carbon economy will require considerable investment from companies; this investment is juxtaposed against the need to generate a profit/return for shareholders. A key question that must be answered in Paris is whether the benefits and opportunities in a low-carbon economy are worth that investment.

The answer will vary vastly depending upon the sector(s) in which a company operates. Consider, for example, different sectors within the energy industry. Clear advantages can be observed for companies that are developing technologies for and manufacturing renewables. However, what are the benefits for companies, such as those in the coal industry, that produce an essential, but higher-CO2, energy source? There will be companies throughout the spectrum being advantaged or disadvantaged by a move to a low-carbon economy. Clearly governments need to take into account not only the environmental, but also the developmental, social, economic, and employment impacts of their commitments.

The recent Business & Climate Summit, held 20–21 May in Paris, generated a number of key messages that are being fed back into the international climate-negotiating process.4 This event gave a window into the business and industry perspective on climate negotiations as it was attended by 1500 mainly business delegates, including a large number of CEOs, across a broad range of sectors. The key takeaways from the Summit can be summarized as follows:

  1. Leading businesses are already taking action to build a prosperous low-carbon economy of the future.
  2. Many businesses are already setting their own internal emissions reduction targets, using internal carbon prices in their investment analyses, increasing energy efficiency, innovating new materials, products and services, aligning their procurement toward low-carbon electricity, and working with suppliers to reduce emissions within their supply chains.
  3. Many recognized that more can be done.

Those businesses present at the Summit also called for an ambitious global climate agreement with appropriate policies from national governments to include ambitious, measurable, and verifiable national commitments, a cooperative mechanism to increase ambition over time, and transparency and accountability mechanisms. There were calls for the use of carbon pricing as a tool to achieve the least-cost global net emissions reductions. Many companies called for a global carbon price but, in equal measure, it was stressed that such tools should be implemented by governments where appropriate and that careful design and implementation was needed to avoid market competitive distortions. There is no “one-size-fits-all” solution.

French President François Hollande at the Business & Climate Summit 2015 (Stephane Lemouton, Sipa via AP Images)

French President François Hollande at the Business & Climate Summit 2015 (Stephane Lemouton, Sipa via AP Images)

The considerable discussion on funding stressed the need for strong support for innovation and deployment of new technologies, including the financing of clean energy research and development and the protection of intellectual property rights. The need for public and private funds to leverage private-sector finance and to de-risk investment toward low-carbon assets, especially in developing countries, was seen as particularly vital.

Finally, there was a call to integrate climate into the mainstream economy through using trade and investment rules to encourage climate action, to support education and training, particularly in developing countries, as well as opening consultative channels to enable decision-makers to get the best possible information from those in the business community.

Many business groups as well as many groups that claim to represent business have developed and championed positions on the outcome of the Paris meeting. Depending upon the motivations and members of the groups, there are many nuances between these positions, but also a number of key messages. These include:

  • Develop an ambitious, predictable, and comprehensive global agreement.
  • Protect economic growth and development.
  • Understand that many businesses support a carbon price as an important tool to drive the transition to a low-carbon economy.
  • Ensure there is no distortion of competitiveness in the global market.
  • Encourage innovation.


Based on my experience attending past climate negotiations and representing various business groups, I believe COP21 will be a success. The enormous efforts by the French government as the Presidency of the conference combined with the drive of many parties to come to a new agreement will ensure this success. As with all recent COPs, whether negotiations are finished in the early hours of Saturday morning, 12 December, or run into the next day remains to be seen.

The foundation of the agreement has already been laid: controls by all countries on their GHG emissions based on INDCs, actions on adaptation, and financing for actions. Still, the work has just begun. The implementation of the structures around basic agreements will take several years to put in place to be ready for the implementation of the new agreement on 1 January 2020. The transformation of the global economy to a new low-carbon future—which has, in some areas, already started—will receive a boost from the outcome of COP21. Of course, COP21 will not be a final action, but it will be an important part of a multi-decadal process and the business community will help define and find the stepping stones needed along the journey.


  1. United Nations Framework on Climate Change. (2015). First steps to a safer future: The Convention in summary,
  2. UN News Centre. (2015, 13 February). States agree key document on route to climate agreement – UN,
  3. Intergovernmental Panel on Climate Change, Working Group III. (2014). Climate Change 2014: Mitigation of climate change,
  4. Business & Climate Summit. (2015). Business & climate summit,


COP21 in Paris will be the 22nd COP to the United Nations Framework Convention on Climate Change (UNFCCC).A The UNFCCC was adopted at the 1992 Rio Convention and entered into force on 21 March 1994. Today there are 196 Parties.

The Convention was augmented in December 1997 at COP3 in Kyoto, Japan, with a protocol in which industrialized countries and those in transition to market economies took on emissions caps. The global emissions cap for six GHGs was an average of 5% below 1990 levels with the first commitment period set as 2008–2012. Specific targets varied from country to country. The Kyoto Protocol entered into force on 16 February 2005 and now has 192 Parties, but a number of key Parties were not fully committed and did not fully ratify it (e.g., U.S.) or did not join the second commitment period (e.g., Canada and Japan).

From 2005 to 2012, the Parties to the Kyoto Protocol negotiated further commitments for Annex I Parties for the years 2012–2020. Two working groups aimed to develop a new agreement ahead of COP15 in Copenhagen, Denmark, in December 2009. However, in a meeting in which there was considerable mistrust between the Parties the Copenhagen Accord was only the “noting” of an agreement.

While the goal of a new agreement was not achieved in 2010, much of the trust lost in Copenhagen was rebuilt, thanks in large part to the dedication and tireless diplomacy of the Mexican Presidency. The 2010 COP in Cancun, Mexico, formally recognized the need for deep cuts in global emissions to limit the global average temperature rise to 2°C. Much groundwork on establishing institutions for the technology and financial mechanisms that would be necessary to implement any global agreement was also laid at the Cancun COP.

The following year at COP17 in Durban, South Africa, there was an agreement to establish a second commitment period under the Kyoto Protocol, 2013–2020. Since COP17, much discussion and little action has taken place in the attempt to understand Parties’ relative positions and the scope of what could be viable in the new climate agreement. For example, at COP18 in Doha, Qatar, in December 2012, an agreement was reached on the amendments to the Kyoto Protocol to establish its second commitment period.

In Warsaw, Poland, at COP19, the Intended Nationally Determined Contributions (INDCs) were formed. Using the INDCs gives each Party the opportunity to develop their own strategies and goals for reducing emissions. That these emission reduction goals are being developed by the Parties individually is a critical difference from the Kyoto Protocol. The INDC approach means that the new 2015 agreement will be based on a bottom-up national pledge system, rather than negotiated top-down targets. On the finance side, the Warsaw International Mechanism on Loss and Damage and the Warsaw Framework for REDD+ were established to assist countries dealing with the impacts of climate change and support major initiatives to prevent deforestation, respectively.

The most recent meeting, COP20, in Lima, Peru, focused on the preparation of the draft negotiating text of the 2015 agreement, as well as what should be included in specific INDCs. The Lima Call for Climate Action, while pushing forward the process, did little to advance the substance within the negotiating text, except for creating two extra negotiating meetings in 2015 leading up to COP21.


A.     COP6bis was held in 2001 following the inconclusive COP6 in The Hague in 2000.

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Urbanization, City Growth, and the New United Nations Development Agenda

By Barney Cohen
Chief of Branch, Population Division,
Department of Economic and Social Affairs,
United Nations

In September 2015, member states of the United Nations (UN) will meet in New York to finalize a new global development agenda that will guide the international community’s efforts to eradicate poverty, reverse global trends toward unsustainable patterns of consumption and production, and protect and manage the environment over the next 15 years. For the past 15 years, the international community’s efforts have been guided by the UN’s Millennium Development Goals (MDGs), the eight-point agenda adopted by member states in 2000 that focused on eradicating extreme poverty and hunger, achieving universal primary education, promoting gender equality and empowering women, reducing child and maternal mortality, halting the spread of HIV/AIDS, ensuring environmental sustainability, and strengthening global partnerships for development, by the target date of 2015. The world has made notable progress in reducing extreme poverty over those years, in large part because of the remarkable economic growth that China has achieved. Some countries look set to attain all or most of the MDGs prior to the 2015 deadline. Overall, however, progress has been uneven both within and between countries and regions.1 At the same time, signs of global climate change and environmental degradation have become increasingly visible and the international community has come to recognize that global goals and targets for sustainable development need to be reprioritized in order to give environmental objectives a somewhat higher profile.


In designing the new global development agenda, it will be important for policymakers to understand and account for the nature and extent of the major demographic changes likely to unfold over the next 15 years and how such changes can be expected to contribute to or hinder the achievement of the new sustainable development goals. Much will depend, for example, on how well countries manage their cities. Cities have always been focal points for economic activity, innovation, and employment. Historically, most cities developed because of some natural advantage that they possessed in location related to ease of fortification or transportation, access to markets, or access to raw materials. Today, cities play a central role in creating national wealth, enhancing social and economic development, attracting direct foreign investment and manpower, and harnessing both human and physical resources in order to achieve gains in productivity and competitiveness. Cities also offer other advantages that are important for achieving sustainable development. Higher population density associated with urbanization provides an opportunity for governments to deliver basic services such as water and sanitation more cost-effectively to greater numbers of people. Higher population density may also be good for minimizing the effect of humans on local ecosystems. Despite the high rates of urban poverty found in many cities in low-income countries, urban residents, on average, enjoy better access to education and health care, as well as other basic public services such as electricity, water, and sanitation, than people in rural areas. For example, it has been estimated that 94% of urbanites have access to electricity compared with only 68% of rural residents.2

The challenge, of course, is that as cities become ever larger, managing them inherently becomes increasingly complex. A basic determinant of the world’s ability to achieve the post-2015 development agenda will be the quality of governance at all levels. In this context, it is important to note that the structure and organization of urban governance has itself undergone significant changes over the recent past, resulting in solutions to urban problems increasingly being sought at the local rather than the state or national level. This has created an urgent need to strengthen the capacity of local governments charged with solving new and persistent environmental and social service challenges that accompany rapid urban growth so that the benefits of urban living are shared equitably. In many cities, unplanned or inadequately managed urban expansion has led to urban sprawl, pollution, environmental degradation, and, in some cases, heightened exposure to the risk of natural hazards (e.g., floods and landslides). Future urban expansion needs to be undertaken in a more sustainable and inclusive manner, and needs to be accompanied by a reduction in the number of slum dwellers, an expansion of infrastructure to ensure greater access to basic services for the urban poor, and the implementation of policies that preserve the natural assets within cities and surrounding areas, protect biodiversity, and minimize tropical deforestation and changes in land use.


Cities are currently home to just over half of the world’s population and nearly all of the 1.1 billion increase in global population projected over the next 15 years is expected to occur in urban areas. For that reason, the United Nations Population Division has published a new resource, World Urbanization Prospects: 2014 Revision [Highlights]. The report contains the latest official UN estimates and projections of urban and rural populations for major areas, regions, and countries of the world from 1950 to 2050 and estimates and projections to 2030 of all urban agglomerations with 300,000 or more inhabitants in 2014. As such, it was created to provide important insights into the size and characteristics of future urban challenges and opportunities.3

The latest official UN estimates were provided in the 2014 World Urbanization Prospects.

The latest official UN estimates were provided in the 2014 World Urbanization Prospects.

As the report makes clear, urbanization has proceeded rapidly over the past 60 years. In 1950, more than two-thirds of people worldwide lived in rural areas and slightly less than one-third resided in urban areas. In 2014, 54% of the world’s population lived in urban areas, and the coming decades will not only see continued global population growth but also continued urbanization so that all of the growth in global population over the next 15 years is projected to occur in urban areas. Furthermore, those projections show that urbanization, combined with the overall growth of the world population, could result in the addition of another 2.5 billion people to the global urban population by 2050, at which time the world is expected to be one-third rural and two-thirds urban—almost the exact opposite of the situation observed in the mid-20th century (see Figure 1).

FIGURE 1. Estimated and projected populations in urban and rural settings, 1950–20503

FIGURE 1. Estimated and projected populations in urban and rural settings, 1950–20503

Just over the brief span of the next 15 years, the timeframe for the implementation of the new UN development agenda, the world’s urban population is projected to expand 28%. All regions, with the exception of Europe, are projected to increase the size of their urban population by at least 15%—with Africa and Asia projected to have the largest increases of 63% and 30%, respectively (see Table 1).3 Perhaps not surprisingly, given the size of their populations, the greatest urban growth is expected to occur in India, China, and Nigeria. Taken together, these three countries are projected to account for 37% of the total growth of the world’s urban population between 2014 and 2050. By 2050, India is projected to have added an additional 404 million urban residents, China an additional 292 million, and Nigeria an additional 212 million.


The new UN report differs from previous versions because, for the first time, estimates and projections from 1950 to 2030 are provided for all urban agglomerations with populations currently over 300,000. Previously, data were reported only for cities with over 750,000 residents. Although there is obviously much uncertainty about the future course of urbanization and city growth, and, in particular, the exact trajectory of any given city or urban area, the broad trends across regions and across city sizes over a 15-year time horizon can be expected to be reasonably robust and are very clear: The world’s fastest growing cities are located in Africa and Asia and tend to be medium-sized cities of between one and five million residents.

Given the projected increase in the global urban population, it is not surprising that the world is projected to experience not only an increase in the absolute number of large cities, but that the largest cities are projected to reach unprecedented sizes. “Mega-cities”, conventionally defined to be large urban agglomerations of 10 million or more, have become both more numerous and considerably larger in size. In 1990, there were 10 such mega-cities, containing 153 million people. By 2014, the number of mega-cities had nearly tripled to 28, and the population that they contain had grown to 453 million inhabitants, accounting for roughly 12% of the world’s urban dwellers. While Tokyo, currently the world’s largest urban agglomeration with 38 million inhabitants, has grown at an annual rate of roughly 0.6% over the last five years, other megacities such as Delhi (with 25 million residents) and Shanghai (with 23 million) have been growing at more than 3% per annum over recent years. Such rapid growth is creating significant challenges for local authorities charged with delivering essential services. Rounding out the list of the top 10 largest urban agglomerations are Mexico City, Mumbai, and Sao Paulo, each with around 21 million, Osaka with just over 20 million, Beijing with slightly under 20 million, and New York-Newark and Cairo, each with around 18.5 million inhabitants.


While there is no doubt that large cities will play a significant role in absorbing future anticipated growth, the new report also makes clear that at least for the foreseeable future the majority of the world’s urban residents will continue to live in far smaller urban settlements.3 In 2014, close to one-half of the world’s urban population lived in settlements with fewer than 500,000 inhabitants whereas only around one in eight lived in the 28 mega-cities with 10 million inhabitants or more. Although the percentage of the urban population living in relatively smaller urban settlements is projected to shrink over time, even in 2030, the anticipated final year for the implementation of the soon-to-be-adopted new UN development agenda, small cities and towns will still be home to around 45% of the population. Typically, residents of small cities in developing countries suffer a marked disadvantage in the provision of basic services, including provision of piped water, sanitation, and electricity, compared to residents of medium or large cities. Furthermore, researchers have found that in developing countries, rates of poverty are typically higher in smaller cities than in medium or larger cities, and that infant and child mortality are negatively proportional to city size.4 Given the role that will be played by small cities in accommodating future population growth, improving the provision of basic services in such cities must remain a priority.

Urbanites have better access to basic services, such as water, trash removal, and electricity.

Urbanites have better access to basic services, such as water, trash removal, and electricity.


It has long been recognized that the size, composition, and spatial distribution of human populations can substantially affect the likelihood of achieving sustainable development goals. Over 20 years ago, in 1994, the International Conference on Population and Development’s Programme of Action pointed out that unsustainable consumption and production patterns were contributing to the unsustainable use of natural resources and environmental degradation as well as to the reinforcement of social inequities and poverty. In designing the new post-2015 development agenda, member states of the UN need to ensure that efforts to improve the quality of life of the present generation are far-reaching, broad, and inclusive, but do not compromise the ability of future generations to meet their own needs. Accomplishing these ambitious goals will depend on identifying strategies to expand access to resources for growing numbers of people, eradicate poverty, increase standards of living, reduce unsustainable patterns of consumption and production, and safeguard the environment.

Cities have become the principal venue for attempting to achieve the goals and targets of the new development agenda. Consequently, one of the central challenges over the next 15 years is finding means to take full advantage of the potential benefits of urbanization and city growth in ways that lessen the obvious potential negatives. The realization by the international community that, alongside poverty reduction, environmental objectives must feature more prominently in any new list of global goals and targets suggests that attention to issues of energy use and energy efficiency5 are likely to attract much more attention than ever before. Continued urban population growth combined with rising standards of living suggests that energy use and greenhouse gas emissions will be much higher in the future, unless there is concerted action to reduce them. Therefore, one essential element of the new sustainable development agenda will be to encourage local authorities to invest in new cleaner energy infrastructure relying on high-efficiency, low-emissions fossil-fuel technologies and utilize new technologies that take advantage of alternative energy sources.


The views expressed in this article are those of the author and do not necessarily reflect those of the United Nations.


  1. United Nations. (2014). The millennium development goals report: 2014. New York: United Nations,
  2. International Energy Agency (IEA). (2011) World Energy Outlook 2011. Paris: IEA.
  3. United Nations. (2014). World urbanization prospects: The 2014 revision [Highlights]. New York: United Nations),
  4. National Research Council. (2003). Cities transformed: Demographic change and its implications in the developing world. Washington, DC: National Academies Press.
  5. International Energy Agency (IEA). (2014). Capturing the multiple benefits of energy efficiency. Paris: IEA.


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Upgrading the Efficiency of the World’s Coal Fleet to Reduce CO2 Emissions

By Ian Barnes
Associate, IEA Clean Coal Centre

Coal remains an important source of energy for the world, particularly for power generation. During the last decade the demand for coal has grown rapidly, as has the demand for gas, oil, nuclear, and renewable energy sources. Various projections for future growth in energy demand suggest that this trend will continue, dominated by coal use in the emerging economies, particularly China and India. Continuing pressure to cut CO2 emissions to mitigate the effects of climate change, specifically to limit the average rise in global temperature to between 2°C and 3°C, will require halving (from current levels) CO2 emissions by 2050.

To contribute to this goal, emissions from coal-fired power generation will need to be reduced by around 90% over this period: Cuts this deep will require carbon capture and storage (CCS). In the International Energy Agency (IEA) 450 ppm CO2 climate change scenario, around 3400 large-scale CCS plants must be operating globally by 2050 to abate the required amount of CO2 emissions.1 At the same time, the growing need for energy, and its economic production and supply to the end user, must remain central considerations in power plant construction and operation.

In 2012, the IEA concluded that, in general, larger, more efficient, and hence younger coal-fired power plants are most suited for economic CCS retrofit. However, the agency also found that only around 29% of the existing installed global coal-fired fleet could be retrofitted with CCS. Furthermore, on average, the efficiency of existing global coal-fired capacity is comparatively low, at about 33% (net HHV basis for all loads, all coals, and all steam conditions)A, although the recent establishment of large tranches of modern plants, particularly in China, is raising this figure. This article examines the first step in the decarbonization of the coal-fired electricity sector: increasing power plant efficiency.

Recently the IEA CCC published a study evaluating how improving coal-fired power plant efficiency would reduce CO2 emissions. For all nations evaluated, increasing the efficiency of the fleet of coal-fired power plants offered considerable CO2 emission reduction benefits, although variability was observed in the time frame in which such benefits could be realized.


Operating at lower efficiency means that relatively large amounts of coal must be used to produce each unit of electricity. As coal consumption rises, so do the levels of CO2 and other emissions. Upgrading existing plants and building new high-efficiency, low-emissions (HELE) coal-fired power plants addresses climate change concerns in two important ways. In the near term, emissions can be reduced by upgrading existing plants or building new HELE plants. Such plants emit almost 20% less CO2 than a subcritical unit operating at a similar load. Over the longer term, HELE plants can further facilitate emission reductions because coal-fired plants operating at the highest efficiencies are also the most appropriate option for CCS retrofit. For these reasons, there is considerable global interest in HELE technologies. Figure 1 illustrates the impact of employing progressively more effective HELE technologies and CCS on CO2 abatement (presented in terms of LHV at full load with hard coal).

FIGURE 1. Reducing CO2 emissions from pulverized coal-fired power generation

FIGURE 1. Reducing CO2 emissions from pulverized coal-fired power generation

The terms subcritical, supercritical, ultra-supercritical (USC), and advanced ultra-supercritical (AUSC) describe the steam conditions by which electricity is generated in a thermal power plant. HELE technologies center on improvements to the steam cycle, allowing for higher steam temperatures and pressures and the consequent improvement in the steam cycle efficiency. A switch from subcritical to current USC steam conditions raises efficiency by around four to six percentage points. Historically, the majority of pulverized coal-fired plants were based on subcritical steam-cycle technology, but supercritical technology is now widespread, largely due to improvements in boiler tube materials. Table 1 summarizes the differences in operating pressures and temperatures for various types of coal-fired plants currently in operation. Although the definitions of supercritical and USC vary from country to country, the ranges cited in the table are used frequently.

table 1 barnes

Supercritical plants can be found in 18 countries and are now the norm for new plants in industrialized nations; USC steam cycles are now the state of the art. A current coal-fired plant operating with a high-efficiency USC steam cycle not only has improved efficiency, but is also more reliable and has a longer life expectancy.

Whereas the first supercritical units were relatively small (typically less than 400 MWe), larger units of up to 1100 MWe are now being built based on USC technology (such as the Neurath USC lignite-fired plant in Germany) and even larger units are planned.

Developments in AUSC steam cycles are expected to continue this trend. AUSC coal-fired plants are designed with an inlet steam temperature to the turbine of 700–760°C. Average metal temperatures of the final superheater and final reheater could be higher, up to about 815°C. Nickel-based alloy materials are needed to meet this demanding requirement. Various research programs are underway to develop AUSC plants. If successful, a commercial AUSC-based plant would be expected to achieve efficiencies in the range of 45–52% (LHV [net], hard coal). A plant operating at 48% efficiency (HHV) would emit up to 28% less CO2 than a subcritical plant, and up to 10% less than a corresponding USC plant. Commercial AUSC plants could be widely available by 2025, with the first units coming online in the near future.

To illustrate the potential of HELE technologies, Figure 2 summarizes the impact of different steam-cycle conditions on an 800-MWe power station boiler burning hard coal and operating at an 80% capacity factor. Such a unit would generate 6 TWh of electricity annually and emit the quantities of CO2 shown in the figure, depending on its steam-cycle conditions and corresponding efficiency. Thus, replacing a unit of this type operating with a subcritical steam cycle with a unit based on AUSC technology (under development) would result in savings of CO2 in the region of 30%.

FIGURE 2. The impact of HELE technologies on CO2 emissions

FIGURE 2. The impact of HELE technologies on CO2 emissions


Across nations, a legacy of using coal to produce electricity has given rise to coal fleets of differing age and efficiencies. Countries with a long history of using coal to generate power tend to have mature coal fleets that are maintained and upgraded with replacement components and new plants when necessary. Newer coal users tend to have younger coal fleets, in some cases based on the best available technology. These two extremes are well illustrated by comparing the coal fleet profiles of Russia and South Korea (Figures 3 and 4, respectively). Russia’s fleet is older, and thus consists of mostly subcritical plants, whereas South Korea’s recently built and rapidly growing fleet is made up primarily of supercritical and USC plants.

FIGURE 3. Russian coal-fired power fleet by year of construction and steam-cycle conditions *Planned or under construction

FIGURE 3. Russian coal-fired power fleet by year of construction and steam-cycle conditions
*Planned or under construction

FIGURE 4. South Korean coal-fired power fleet by year of construction and steam-cycle conditions *Planned or under construction

FIGURE 4. South Korean coal-fired power fleet by year of construction and steam-cycle conditions
*Planned or under construction

The IEA CCC recently examined the potential of HELE coal-fired power to reduce CO2 emissions; the principal coal-consuming nations were studied: Australia, China, Germany, India, Japan, Poland, Russia, South Africa, South Korea, and the U.S. Notably, the coal-fired power fleets of these countries vary in age and efficiency, and have different local conditions and policies that affect the possible scope for implementing HELE technologies.

The coal fleet profile of each country to meet future electricity demand was assessed under three scenarios: continuing electricity generation based on the existing fleet and retiring and replacing older plants on the basis of a 50-year or 25-year plant life. The potential impact of HELE upgrades on CO2 emissions was quantified and costs of implementation were estimated. Industry norms were used for unit efficiency and availability and current assumptions on capture rates from CCS retrofitted to HELE plants were assumed.


As China and India represent the largest emerging economies and both rely heavily on coal, the key findings for the Chinese and Indian studies are summarized below.


The Chinese coal-based fleet is the largest in the world, as are the associated CO2 emissions. These plants account for approximately 41% of the global coal-fired capacity and are responsible for approximately 37% of global CO2 emissions from coal through the production of electricity.2 China’s coal-based fleet—with a median age of less than 20 years—is by far the youngest currently in operation. In addition, a significant number of the newer plants employ supercritical or USC steam conditions.

By the end of 2013, China’s total electricity capacity was 1247 GW. With a reported coal-fired power generation capacity of over 786 GW and an annual total generation of 3947 TWh (2013 data),3 China is the world’s largest producer of power from coal. Predictions on the role of coal in China’s future energy requirements generally agree that coal will continue to be a very significant contributor to the country’s energy needs, although estimates of the relative importance of coal with respect to other primary energy sources differ. China is actively seeking to diversify its electricity supplies. The electricity capacities from other energy sources currently stand at 22% for hydroelectric, ~8% for other renewables (led by wind at ~6% and solar at ~2%), 6% for natural gas, and 1% for nuclear power. Although power from these sources is growing, they still account for a relatively small share of China’s energy generation profile, with coal still responsible for about 70% of electricity generation.

The Chinese government has set a target to raise non-fossil fuel energy consumption to 11.4% of the total energy mix by 2015 as part of its 12th Five-Year Plan. The U.S. Energy Information Administration (EIA) projects coal’s share of the total energy mix to fall to 59% by 2035 due to anticipated higher energy efficiencies and China’s goal to reduce its carbon intensity.4 Still, absolute coal consumption is expected to double over this period, reflecting the large growth in total energy consumption.

China is the premier example of a country benefitting from an actively pursued HELE upgrade policy. By utilizing state-of-the-art USC plants for new and replacement capacity, and with the retirement of older, less efficient units, CO2 emissions are projected to rise less steeply than the increase in demand for coal-based electricity; emissions are projected to reach 6136 Mt in 2040. If China continues to adopt the best technology and retire older units on a roughly 25-year timescale, a largely AUSC-based coal fleet would see projected CO2 emissions actually fall between 2035 and 2040; in this case the CO2 emissions are projected to be 5153 Mt in 2040 (a 16% reduction over the base case scenario), despite a continuing increase in demand. If the most effective CO2 abatement pathway is followed (25-year plant retirement, AUSC upgrades after 2025, CCS installation) emissions could fall to 750 Mt in 2040 (see Figure 5). Although the analysis presented here does not incorporate China’s recent announcement to peak coal utilization by 2020, such a policy approach would certainly require continued aggressive deployment of HELE coal-fired power plants.

FIGURE 5. China’s coal-based power fleet composition and CO2 emissions under a plan to retire plants after 25 years of operation, from 2015–2040

FIGURE 5. China’s coal-based power fleet composition and CO2 emissions under a plan to retire plants after 25 years of operation, from 2015–2040


India has the third largest coal-fired power plant fleet installed in a single country. The Indian coal fleet contributes approximately 6% of the global coal-fired capacity with approximately 8% of global CO2 emissions from coal through the production of electricity.2 India has a relatively high share of smaller units (i.e., <400 MWe) and many of India’s power plants burn high-ash coal (up to 50%). The majority of the Indian coal-fired power plant fleet is based on subcritical technology, although some recently built plants have incorporated supercritical steam cycles. Overall, the fleet is relatively young and a very large portfolio of supercritical plants is reported as planned or under construction, which will make India the second fastest growing user of coal for electricity generation (after China) by 2020.1

India’s 12th Five-Year Plan (2012–2017) sets a goal that 50–60% of new coal-fired plants must use supercritical technology, although observers suggest that significantly less is likely to be achieved. Early indications of India’s longer-term policy direction suggest that the 13th Five-Year Plan (2017–2022) will stipulate that all new coal-fired plants must be at least supercritical, thus no new subcritical plants would be allowed.5

India is a rapidly developing country with considerable energy poverty and rapidly growing energy demand. Growth in coal-based energy demand is projected to extend to 2040, with no sign of leveling off. If new capacity is based on the best available HELE technologies and older plants are retired after 25 years and replaced with HELE units, CO2 emissions will first flatten out and then decline, despite increasing demand: 764 Mt in 2015 to 1063 Mt in 2040; a 39% increase (see Figure 6). With implementation of CCS, emissions could be reduced much more rapidly.

FIGURE 6. India’s coal-based power fleet composition and CO2 emissions if subcritical plants were retired after 25 years of operation, from 2015–2040

FIGURE 6. India’s coal-based power fleet composition and CO2 emissions if subcritical plants were retired after 25 years of operation, from 2015–2040


The results of the IEA CCC study reveal trends for the major coal-consuming countries. Some trends are specific and depend on the profile of the respective coal fleet and the prospects for growth or decline in coal-sourced electricity, while other trends are more generally applicable. A few key conclusions can be garnered from the larger IEA CCC analysis:

  • Countries experiencing a prolonged period of growth necessitating additional power capacity and having a relatively new coal fleet are characterized by rising CO2 emissions, but these are projected to be offset by the use of AUSC over USC plants for new builds (e.g., China and India).
  • Countries experiencing a prolonged period of growth necessitating additional capacity and having a more mature coal fleet are characterized by rising CO2 emissions, but these are projected to be offset by the use of AUSC over USC (e.g., South Africa), particularly when older plants are retired and replaced by AUSC units.
  • Countries experiencing a prolonged period of growth necessitating additional capacity and having an old, relatively inefficient coal fleet see falling levels of CO2 emissions, even with growth in electricity demand (e.g., Poland and Russia).
  • Countries experiencing relatively low to moderate levels of growth and having an efficient coal fleet do not see significant reductions in CO2 emissions until 2040 when some older plants are projected to retire (e.g., South Korea).
  • As an existing coal fleet transitions to a HELE composition it becomes smaller with respect to installed capacity. This potentially benefits the siting and replacement of plants, particularly in countries where planning regulations are demanding and time consuming.
  • The greatest gains are seen when plant life is limited to 25 years (an evolving practice in China) rather than 40 years or more (common in OECD countries). Policies and incentives to encourage shorter timescale plant renewal would enhance CO2 savings.
  • When CCS readiness is considered, in all cases, the 25-year plant life scenario represents the best option for CCS deployment as all coal fleets transition to a high HELE composition quickly and enjoy maximum CO2 abatement as any remaining lower efficiency capacity is retired. This is particularly evident in the Indian case where the effects of rapidly increasing electricity demand are attenuated by a combination of HELE and CCS technologies.
  • Economics will govern the decision to replace plants unless policies and incentives drive the selection toward HELE technologies.

HELE plant upgrades can be considered a “no regret” option for coal-fired power plant owners and operators. A current state-of-the-art coal-fired plant operating with a high-efficiency USC steam cycle will be more efficient, more reliable, and have a longer life expectancy than its older subcritical counterparts. Most significantly, it will emit almost 20% less CO2 compared to a subcritical unit operating under similar load. In the near future, developments in AUSC steam cycles promise to continue this trend: A plant operating at 48% efficiency would emit up to 28% less CO2 than a subcritical plant, and up to 10% less than a corresponding USC plant. In addition, when CCS is available it will likely be applied to higher efficiency plants, making HELE a first step toward deep carbon emission reductions.

It is hoped that this study has provided an overview of what might be achieved in the major coal-using countries through an aggressive uptake of HELE technologies and the role they can play in reducing CO2 emissions. Deeper analysis by the IEA CCC is planned on a country-by-country basis to provide policy makers and planners with a local perspective on how HELE implementation can reduce emissions.

Steam turbines at the ultra-supercritical Waigaoqiao No. 3 (Shanghai) (photo courtesy of IEA CCC)

Steam turbines at the ultra-supercritical Waigaoqiao No. 3 (Shanghai) (photo courtesy of IEA CCC)

A. Coal-fired power plant efficiencies are determined by properties such as the steam-cycle conditions, coal grade, load factor, etc. and are often reported in terms of LHV or HHV. Efficiencies provided in lower heating value (LHV), have subtracted the heat required to vaporize any moisture in the coal and assume that heat is not recovered. The higher heating value (HHV) includes the heat required to vaporize the moisture in the fuel and is usually about 2–3 percentage points higher than LHV.


  1. International Energy Agency (IEA). (2012). Technology roadmap: High-efficiency, low-emissions coal-fired power generation,
  2. IEA. (2010). CO2 emissions from fuel combustion,
  3. China Electricity Council. (2014). Generation,
  4. Energy Information Administration (EIA). (2013). Annual energy outlook 2013,
  5. George, T. (2014). Private communication. Second Secretary Energy & Resource Security, British High Commission, New Delhi, India.

This article is based on an IEA CCC report, “Upgrading the Efficiency of the World’s Coal Fleet to Reduce CO2 Emissions”, by Ian Barnes, CCC/237, 99 pp, July 2014. The report is available for download from the IEA Clean Coal Centre Bookshop:; the author can be reached at

The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.
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The Energy Frontier of Combining Coal and Renewable Energy Systems

By Stephen Mills
Senior Consultant
IEA Clean Coal Centre

The world is undoubtedly hungry for energy and this hunger is growing. There are strong incentives to develop improved sources of energy. By 2040, the world’s population will have reached nearly nine billion.1 All of these people will need to be housed, fed, and have the opportunity to make a living; this inevitably means that much more energy is going to be needed. By 2040, global energy demand will be about a third greater than current levels.2 Oil, natural gas, and coal will continue to be used widely, although in some situations, the increasing use of renewable energy sources may reduce the amount of fossil fuels currently used. Regardless, on a global basis, coal will continue to play a major role. This will be particularly true in some of the emerging economies where growing industrialization and urbanization continue to relentlessly drive electricity demand upward.


Poland’s Belchatów coal-fired power station is Europe’s largest thermal power plant (courtesy PGE Elektrownia Belchatów).

Poland’s Belchatów coal-fired power station is Europe’s largest thermal power plant (courtesy PGE Elektrownia Belchatów).

At the moment, over 1.2 billion people lack access to any electricity, and another two billion are considered to have inadequate access. A key goal of the 2010 Copenhagen Accord is to provide energy to these underserved populations. There may be few energy source options available—in some countries, coal is the only economically available bulk source capable of providing reliable energy. Although its use is set to decline in some developed economies, coal will continue to be used widely and in considerable quantities. For over a decade, global coal consumption has risen steadily; in some non-OECD countries, in particular, both production and consumption have increased dramatically. During this time, consumption has risen by nearly 60%, from 4.6 Gt in 2000 to about 7.8 Gt in 2012.3 Despite efforts to diversify, coal remains vitally important for many economies. Since 2000, apart from renewables, it has been the fastest-growing global energy source. It’s the second source of primary energy after oil, and provides more than 30% of global primary energy needs.

The biggest individual coal reserves are in the U.S., Russia, China, Australia, and India. In all of these countries, coal is used to generate large percentages of electricity. In several, it also provides important economic benefits as it is exported to other power-hungry economies. At the moment, coal’s principal use remains electricity generation; coal-fired power plants produce 41–42% of the world’s electricity. In the coming years, electricity will continue to be provided by many different generating technologies, but the projected combinations are highly site-specific. The IEA World Energy Outlook (2012) suggests that, for the foreseeable future, power production from most sources will continue to increase (Figure 1).4 In many countries, coal and renewable energy systems are being deployed at greater percentages and, thus, there is increased interest in how to optimally integrate these systems. In fact, there are a significant number of opportunities.

FIGURE 1. Global power generation mix4

FIGURE 1. Global power generation mix4


With the ever-increasing use of all types of fossil fuels, there has also been a marked increase in the uptake of renewable energy sources. In many economies, these now represent a rapidly growing share of electricity supply; Table 1 shows the top regions and countries at the end of 2012.


In 2013 renewables made up more than 26% of global generating capacity; in 2013 they produced 22% of the world’s electricity. Global renewable power capacity continues to increase. In 2013, hydropower and solar PV each accounted for about 33% of new renewable capacity, followed by wind at about 29%.5

Several driving forces support the growth in renewables. All developed nations rely heavily on an adequate and accessible supply of electricity and, for a long time, demand has continued to rise in nearly every country. However, in recent years, concerns over issues such as the depletion of energy resources and global climate change have been heightened. The preferred response of many western governments has been a supply-side strategy—namely, to raise the share of renewables (especially renewables other than hydropower) in the energy mix toward 20% and beyond. To date, wind power has emerged as the most competitive and widely deployed renewable energy, although levels of solar power are also growing steadily. Renewable energy technologies such as wind and solar have obvious features that make their use attractive. Although initial capital costs for renewables-based systems can be high, operating costs can be low; emissions generated during day-to-day operation are effectively zero.

Especially in faster-growing energy markets, these renewable energy systems are not replacing existing or even new coal-fired power plants. Renewables and coal-fired power generation are growing simultaneously. Therefore, it is worth exploring the many options for combining these very different forms of energy in the most cost-effective, environmentally conscious, and efficient means possible. A growing number of hybrid coal-renewables systems have been proposed or are being developed around the world, several of which could offer significant potential.

Coal and Biomass

Combining biomass with coal is a prime example of combining renewables and coal. Such a combination is already deployed fairly widely in the form of cofiring biomass in large conventional coal-fired power plants. Around the world, a growing number of power plants regularly replace a portion of their coal feed with suitably treated biomass. More than 150 coal-fired power plants now have experience with cofiring biomass or waste fuels, at least on a trial basis. There are ~40 pulverized coal combustion (PCC) plants that cofire biomass on a commercial basis, with an average of 3% energy input from biomass.6

International Power’s 1-GW Rugeley power station in the UK. Like many others, this power plant has trialed cofiring various biomass materials with coal (courtesy Russell Mills Photography).

International Power’s 1-GW Rugeley power station in the UK. Like many others, this power plant has trialed cofiring various biomass materials with coal (courtesy Russell Mills Photography).

Biomass comes in many forms and can be sourced from dedicated energy crops (such as switchgrass and miscanthus), short-rotation timber, agricultural crops and wastes, or forestry residues. When combined with coal, biomass can provide a number of advantages. However, its use on a large commercial scale could create a number of issues. For example, the volumes to be harvested and handled can be substantial, some forms may be subject to limited or seasonable availability, and various pre-treatments may be needed. Inevitably, such challenges can add complexity and cost to energy production.

Co-utilization of coal and biomass need not be limited to co-combustion in existing power plants—there are a number of other possibilities such as co-gasification. Coal gasification is a well-established versatile technology. Combining these two different feedstocks can be beneficial. For instance, facilities that co-gasify biomass in large coal gasifiers can achieve high efficiencies and improve process economics through greater economies of scale compared to a biomass-only facility. Such a combination can also help reduce the impact of fluctuations in biomass availability and its variable properties. Combining biomass and coal in this way can be useful, both environmentally and economically, as it may be possible to capitalize on the advantages of each feedstock, and overcome some of their individual drawbacks. Biomass can have an impact on CO2 emissions from a combustion or gasification process. Replacing part of the coal feed with biomass (assuming that it has been produced on a sustainable basis) can effectively reduce the overall amount of CO2 emitted. Potentially, the addition of carbon capture and storage (CCS) technology could result in a carbon-neutral or even carbon-negative process. Globally, considerable quantities of biomass are potentially available—in many countries, biomass remains an underexploited resource.

Similar to many conventional coal-fired power plants, several commercial-scale, coal-fueled, integrated gasification combined cycle (IGCC) plants in operation have at least trialed combining biomass with their coal feed, and several proposed IGCC projects aim to do the same. For instance, a planned IGCC and chemicals production plant (with CCS) at Kędzierzyn in Poland will co-gasify coal and biomass.7 To date, useful operational experience in co-gasifying has been gained with all major gasifier variants (entrained flow, fluidized bed, and fixed bed systems). Different types of coal have been co-gasified successfully with a wide range of materials, many of which are wastes that would have otherwise ended up in landfills or, at least, created disposal problems.

Co-utilizing coal and biomass is not limited to power generation. In a number of countries, hybrid concepts for the production of SNG, electricity and/or heat, and liquid transport fuels have either been proposed or are in the process of being developed or tested. Coal/biomass co-gasification features in some of these. However, as well as incorporating biomass, some propose to take this a step further by adding yet another element of renewable energy to the system, generally by incorporating electricity generated by intermittent renewables (such as wind and solar power).

Coal, Wind, Solar, and Geothermal

Wind power has become the most widely deployed renewable energy. In 2013, global capacity hit a new high of 318 GW. In that year, China alone installed more than 16 GW; by 2020, the IEA projects the country will more than double its wind power capacity from the present level of 90 GW to around 200 GW.8 For comparison, the European Union countries have a combined ~90 GW of installed capacity. In 2013, wind surpassed nuclear to become the number three source of energy after coal and hydropower in China.9 Reportedly, this is part of the greatest push for renewable energy that the world has ever seen.10

Most major wind and solar facilities do not operate in isolation. Generally, they feed electricity into existing power grids or networks. Often, such grids are fed by a variety of different types of power plants—there may be various combinations of coal- and gas-fired power plants, some hydro, and possibly nuclear. The grid makeup and ratio between plant types is never the same, as these factors differ from country to country based on the local circumstances. On the face of it, the addition of a large amount of wind power into a grid, for example, is a positive development. However, a large input from intermittent sources into existing power systems can upset grid stability and have major impacts, particularly on how thermal power plants within the system operate. Many coal- and gas-fired power plants no longer exclusively provide baseload power, but are now required to operate on a more flexible basis. Many are increasingly switched off and on, or ramped up and down, much more frequently than they were designed to be. Inevitably, this is guaranteed to throw up a number of issues—significantly increasing wear and tear on plant components, reducing the operating efficiency of units not designed for variable operation, and impairing the effectiveness of emission control systems. Ideally, such important impacts should be taken into consideration and factored into any energy-producing scheme, but this is particularly true in cases where coupling intermittent renewables with conventional thermal power plants is being proposed.

Clearly, the most significant drawback with wind and solar power is their intermittency. Consequently, periods of peak power output often do not correspond with periods of high electricity demand, and vice versa. At times, there can be significant amounts of surplus unwanted electricity available, particularly from wind farms. This can be quite a widespread phenomenon, and the usual solution is to take wind turbines offline. However, rather than “waste” this electricity, it would be much more beneficial to find an effective means of using it. One option is to use electricity not needed to fill demand to electrolyze water, producing hydrogen and oxygen. Both gases have the potential to be component parts of hybrid energy systems and there are various schemes that propose feeding the hydrogen into syngas from gasification systems, use it in fuel cells or directly as a transport fuel, or combust it in gas turbines to generate electricity.

Smøla wind farm in Norway (courtesy Statkraft)

Smøla wind farm in Norway (courtesy Statkraft)

Similarly, the oxygen could be used for a host of commercial and industrial applications, or fed to a coal/biomass gasifier or an oxy-fuel combustion plant to generate electricity. Different concepts and schemes combining gasification, intermittent renewables, and electrolysis are currently being examined. Some aim to incorporate carbon capture and storage. For example, an on-going project in Germany is combining coal-based power generation with aspects of carbon capture and wind-generated electricity with trials of advanced electrolyzer technology (to produce hydrogen and oxygen from water).11 Success could encourage increased uptake of, for instance, electrolysis, as a component part of various coal/renewables systems. Assuming that the economics can be made to work, several schemes look promising.

Another ongoing project in Germany is expected to lead to significant improvements in the overall efficiency of the electrolysis process: E.On’s power-to-gas project at Falkenhagen. This technology utilizes multiple electrolyzers driven by excess electricity from a nearby wind farm to provide the power to produce hydrogen and oxygen. Output from the region’s wind farms frequently exceeds demand, so instead of taking the turbines offline when this happens, some of the electricity is now being fed to the electrolyzers. In this case, the hydrogen produced is being injected into the local natural gas grid, which acts as a large storage system. Effectively, it’s a clever way of storing renewable energy.

E.On’s power-to-gas project at Falkenhagen in Germany (courtesy E.On)

E.On’s power-to-gas project at Falkenhagen in Germany (courtesy E.On)

There is also an opportunity to integrate coal-fired power plants with renewable sources of thermal energy, such as geothermal or solar thermal. The benefit of this type of integrated hybrid system is that the renewable source of energy can take advantage of the existing infrastructure of the coal-fired power plant, such as the steam cycle, connection to the grid, and transformers. Generally, this makes the economics much more attractive compared to a stand-alone renewable plant. Obviously, the availability of the renewable resource at the coal-fired power plant site is a prerequisite for such hybrid systems to be successful.

Hybrid thermal systems operate by using heat from renewable energy to increase the temperature of the coal-fired power plant boiler feedwater. This increases the efficiency of the power plant, effectively displacing some coal for renewable energy (or using the same amount of coal and producing more electricity). Such thermal hybrid projects may be the most cost-effective option for large-scale use of solar thermal and geothermal energy, although, to be employed, this approach must be recognized under renewable energy incentives. In the future, there may also be an opportunity for renewable sources of energy to provide the thermal load required for carbon capture and storage, thus significantly reducing the overall impact to the power plant and contributing to large-scale reductions in greenhouse gas emissions.

Currently, around 15 hybrid solar thermal plants, including those on coal- and natural gas-fired power plants, are being developed, with a total capacity of 460 MW.12 Thermal hybrid projects based on unconventional geothermal resources are at an earlier stage of development and the field will require additional research prior to large-scale demonstrations.13


Some systems are at early stages in their development or have been undertaken at a very small size, hence extrapolating to commercial scale and obtaining firm process costs remains problematic. For a variety of reasons, not all of the different schemes being considered appear to be technically and/or economically viable. However, some do appear to be more robust. On-going developments (in, for instance, gasifier and electrolyzer design) should improve cost competiveness. Where hydrogen and/or oxygen production forms part of a hybrid energy scheme, reductions in the cost of electricity provided by renewable energy sources (such as wind and solar) would also be beneficial in making electrolysis more cost effective. Some examples of on-going hybrid projects are given in Table 2. Although some are currently focused only on biomass, potentially different elements from these processes could also be incorporated into systems fueled by coal/biomass combinations.


A number of projects are more advanced than others, with development programs well underway. Some components (such as co-gasification) have now been well established, and others are under development or being trialed (such as the commercial-scale demonstration of hydrogen production from wind power and testing of advanced electrolyzers). A number of proposed hybrid systems show potential—although in the near to medium term, assuming outstanding technical and economic issues can be resolved fully, most seem likely to be applied initially to niche markets, or to find application under specific, favorable circumstances.


Set against a background of growing global population and rising energy demand, there is a pressing need to come up with new, cost-effective, clean, reliable energy systems. To help tackle this, many hybrid energy schemes have been proposed, some more practical than others. Despite efforts by many countries to diversify their fuel mix, fossil fuels such as coal will continue to provide a significant part of the world’s energy for the foreseeable future. For a number of reasons, where possible, it makes sense to look at coupling coal use with renewable energy sources. Each power-producing system has its own pros and cons, but combining these different systems in creative ways may offer the possibility of overcoming some of these shortcomings. With this in mind, various energy production concepts that propose combining a number of different technologies with coal are being developed around the world.

Hybrid coal and renewable energy systems offer synergistic benefits. (photo courtesy of Russell Mills Photography)

Hybrid coal and renewable energy systems offer synergistic benefits. (photo courtesy of Russell Mills Photography)

To be a practical proposition, as with all power-producing systems, any hybrid scheme needs to be clean, workable, and economically sound. Based on work carried out recently by the IEA Clean Coal Centre, some hybrid systems appear to be viable and have potential.14,15 Although coal and renewable energy sources might appear to be strange bedfellows, it’s not unrealistic to suppose that in the coming years we could see increased deployment of combinations of the world’s two fastest-growing energy sources becoming a reality.


  1. United Nations Population Division. (2014). Concise report on the world population situation 2014,
  2. International Energy Agency (IEA). (2012, 25 July). State of play: New IEA statistics publications highlight latest global and OECD trends across major energy sources,,28615,en.html
  3. IEA. (2014). Coal information,
  4. IEA. (2012). World energy outlook 2012,
  5. Renewable Energy Policy Network for the 21st Century (REN21). (2014). Renewables 2014 global status report,
  6. Adams, D. (2013). Sustainability of biomass for cofiring. CCC/230. London: IEA Clean Coal Centre.,-CCC/230
  7. Cornot-Gandolphe, S. (2012, October). The European coal market: Will coal survive the EC’s energy and climate policies? Paris: Institut Français des Relations Internationals.
  8. IEA. (2011). Technology roadmap: China wind energy development 2050. Available at:
  9. Yang, C. (2013). Wind power now No. 3 energy resource. People’s Daily English Edition,
  10. Shukman, D. (2014, 8 January). China on world’s “biggest push” for wind power. British Broadcasting Corporation,
  11. Farchmin, F. (2013, 6 November). Integration of regenerative energy into Power2Gas by PEM electrolyzer technology. CO2RRECT Project. Smart Grid-Infotage 2013, Munich, Germany,
  12. Electric Power Research Institute. (2012, April). Utility perspective: Solar thermal hybrid projects. Clean Energy Regulatory Forum, National Renewable Energy Laboratory, Golden, Colorado, U.S.,
  13. Bean, N., & Varney, J. (2014). Geothermal assisted power generation for coal-fired power plants. Cornerstone, 2(4), 46–50.
  14. Mills, S.J. (2011). Integrating intermittent renewable energy technologies with coal-fired power plants. CCC/189. London: IEA Clean Coal Centre.
  15. Mills, S.J. (2013). Combining renewable energy with coal. CCC/223. London: IEA Clean Coal Centre.

The author can be reached at


The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.

Gasification Can Help Meet the World’s Growing Demand for Cleaner Energy and Products

By Alison Kerester
Executive Diraector
Gasification Technologies Council

Energy is fundamental to economic growth. Economies cannot grow and people cannot raise their standard of living without adequate supplies of affordable energy. The global demand for energy is projected to rise by 56% between 2010 and 2040, with the greatest increase in the developing world.1 This growing energy demand is a direct result of improving individual prosperity, national economies, and infrastructure, and thus living conditions. With this demand in energy also comes a demand for products to support development.

“Increased flexibility, vastly increased scale, and new applications are driving gasification technologies to gain greater prominence  than ever before.”

“Increased flexibility, vastly increased scale, and new applications are driving gasification technologies to gain greater prominence than ever before.”

Gasification, which can provide cleaner energy and products, is not new. Its origin dates back to the late 1700s when an early form of gasification was used in the UK to create “town gas” from local coal reserves. More modern gasification technologies began to evolve prior to and during World War II as Germany needed to create its own transportation fuels after being cut off from oil supplies. Later, Sasol in South Africa made the first strides in transitioning toward large-scale production of commercial, economically competitive gasification-derived products and was instrumental in developing the foundations of the modern gasification industry.

Today’s advanced gasification technologies incorporate significant improvements over those early versions; increased flexibility, vastly increased scale, and new applications are driving gasification technologies to gain greater prominence than ever before. The wide deployment of gasification technologies can be largely attributed to socioeconomic, energy security, and environmental issues. In addition, there is more variation in gasification technologies, with some developers focused on reducing costs through integration while others focus on smaller, modular gasifiers. Greater deployment of gasification still faces challenges, but the recent upswing, especially in China, clearly demonstrates the advantages of this technology for utilizing domestic energy sources to produce commercial products.

Gasification Basics

Gasification is a thermochemical process that converts carbon-based materials—including coal, petroleum coke, refinery residuals, biomass, municipal solid waste, and blends of these feedstocks—into simple molecules, primarily carbon monoxide and hydrogen (i.e., CO + H2) called “synthesis gas” or “syngas”. It’s quite different from combustion, where large amounts of air are blown in so that the material actually burns, forming carbon dioxide (CO2). There are several basic gasifier designs and a wide array of operating conditions. The core of the gasification process is the gasifier, a vessel in which the feedstock(s) reacts with air or oxygen at high temperatures. The CO:H2 ratio depends, in part, on the hydrogen and carbon content of the feedstock and the type of gasifier. This ratio can be adjusted or “shifted” downstream of the gasifier through the use of catalysts.

A key advantage of gasification systems is that they can be designed to have a reduced environmental footprint compared to combustion technologies. For instance, over 95% of the mercury present in the feedstock can be captured using commercial activated carbon beds. Capturing nearly all the feedstock sulfur is necessary because downstream catalysts are generally intolerant of sulfur. This sulfur can be collected in its elemental form or as sulfuric acid, both of which are saleable products. Slag created from the ash, unreacted carbon, and metals in the feedstock are also captured directly from the gasifier, requiring less equipment than what would be required for post-combustion removal of those same materials in the flue gas of combustion-based systems.

Slag captured from the gasification process (photo provided by Westinghouse Plasma Corp., a division of Alter NRG)

Slag captured from the gasification process (photo provided by Westinghouse Plasma Corp., a division of Alter NRG)

CO2 emissions can also be captured from the syngas in gasification plants. Greater than 90% of the carbon in the syngas stream can be captured as CO2 and processed for utilization and/or storage. Some studies have shown that transportation fuels can be produced with near-zero carbon footprints using gasification of coal and biomass with CO2 capture and storage.2

Gasification typically takes place in an above-ground gasification plant; however, the gasification reaction can also take place below ground in coal seams. With underground coal gasification (UCG), the actual gasification process takes place underground, generally below 1200 feet below the surface in coal seams that are considered not economically mineable. Recent advances in well-drilling technologies are now enabling UCG development of coal seams in the 4000–6000-ft depth range, with increased environmental protection and process efficiency benefits at these depths. The underground setting provides both the feedstock source (the coal) as well as pressure comparable to that of an above-ground gasifier. With most UCG facilities, wells are drilled on two opposite sides of an underground coal seam. One well is used to inject air or oxygen (and sometimes steam) and the other is used to collect the syngas that is produced. The ash and other contaminants are left behind. A pair of wells can last as long as 15 years. Under its New Energy Policies scenario, the International Energy Agency has estimated that emerging economies will account for over 90% of the projected increase in global energy demand.3 UCG could play a unique role in helping meet this rising energy demand by utilizing deep coal seams that would otherwise be unobtainable economically.

Additional information on the technical fundamentals behind gasification is provided at the end of this article.

Today’s Gasification Market

Key Benefits

Finding a path to energy security is a chief concern of nearly every sovereign nation. In the past, fast changing markets have rocked economies that were overly dependent on a single fuel source, such as the oil shocks experienced by the U.S. in the 1970s. Today, perhaps the clearest example is the fact that even as European countries pass sanctions against Russia, they are still highly dependent on Russian natural gas. This dependence could be reduced, or even eliminated, through the use of gasification.

Even within borders, diversification of energy sources is crucial. Although the U.S. has access to inexpensive and seemingly abundant natural gas, the extreme cold resulting from the polar vortex in the winter of 2014 saw rapid spikes in natural gas prices. Around the world, oil and natural gas prices continue to fluctuate dramatically. In addition to avoiding price uncertainty, many nations have a strong strategic desire to use their indigenous energy resources to produce the energy and products needed for economic growth. Gasification facilities can be designed to use the carbon-based feedstock that is most appropriate for a given region.

Environmental concerns are also receiving increased attention globally. For reasons explained previously, gasification can offer environmental benefits in terms of reduction of a wide range of emissions. In addition, CO2 emissions can be significantly reduced if carbon capture, utilization, and/or storage are employed. Although environmental concerns may not be the principal driver for the deployment of gasification today, the advantages are undeniable. For instance, gasification can be employed to create low-sulfur transportation fuels, thus reducing one of the major contributors to urban air pollution.

Modern gasification technologies are extremely diverse in their feedstocks, operational configuration, and products. Gasification converts virtually any carbon-containing feedstock into syngas, which can be used to produce electricity and/or other valuable products, such as fertilizers, transportation fuels, substitute natural gas, chemicals, and hydrogen (see Figure 1 for examples of products from gasification). Polygeneration facilities can produce multiple products, one of which can be electricity, from the same initial stream of syngas; the integration of the different components of polygeneration plants can also increase efficiency and provide an overall reduction in the environmental footprint.

Figure 1. Gasification can yield a tremendous variety of products; the examples shown include only the most common (figure courtesy of Eastman Chemical Company).

Figure 1. Gasification can yield a tremendous variety of products; the examples shown include only the most common (figure courtesy of Eastman Chemical Company).

Gasification processes can be designed to operate using coal, petroleum, petroleum coke, natural gas, biomass, wastes, and blends of these feedstocks; this diversity is the fundamental reason that gasification can be used to address energy security concerns. Coal is by far the most common source of the carbon feedstock for gasification today—a fact that is likely to remain true into the foreseeable future as countries look for a way to utilize their vast coal reserves. China has clearly seized on this fact and is now leading the way on building new gasification projects.

Market Drivers

Gasification is not a stagnant technology, nor is it a one-size-fits-all technology. Its use is growing globally and the regional growth is far from uniform. Generally, industrial gasification facilities are becoming larger by increasing the number of gasifiers as well as the gasifier size. The economies of scale, and sharing key equipment such as the air separation unit among multiple gasifiers, are bringing down the cost of the final products. However, these large facilities also come with a billion-dollar-plus price tag, so even though the end products may be competitive, in some instances the upfront costs are prohibitive. In such cases there are other options; project developers can turn to smaller, more nimble gasification facilities that are also able to produce power and products. These smaller projects could bring reliable power to a mini-grid. For instance, SES’ fluidized bed gasifier can be used to gasify a wide range of feedstocks without changing the gasifier design, making it a contender for distributed power generation.

Today’s gasification technologies are able to meet market needs throughout the world. To track projects, the Gasification Technologies Council maintains the Worldwide Gasification Database.4 This database is being updated annually, with the next update due in late 2014. The database lists 747 projects, consisting of 1741 gasifiers (excluding spares). Of the 747 facilities, 234 of them, with 618 gasifiers, are active commercially operating projects. As of August 2013, 61 new facilities with 202 gasifiers were under construction with an additional 98 facilities incorporating 550 gasifiers in the planning phase.5 The cumulative global gasification capacity projected through 2018 is shown in Figure 2.

Figure 2. Cumulative worldwide gasification capacity and projected growth

Figure 2. Cumulative worldwide gasification capacity and projected growth4

Preferred Products

Chemical production is the most common application of gasification worldwide (see Figure 3). Synthetic fuels (both liquid and gaseous) are also becoming increasingly important. The second most common application is liquid fuels, although there is also a large amount of planned production of gaseous fuels. About 25% of the world’s ammonia and over 30% of the world’s methanol is produced through gasification.5


Figure 3. Gasification by application

Figure 3. Gasification by application4

In contrast, gasification for power has declined sharply, with many of the planned projects in the U.S. no longer proceeding.6 The emergence of abundant and cheap natural gas has been a game changer, making coal gasification less economically competitive in North America. In addition, environmental regulations in the U.S. have resulted in few new coal-based gasification projects being planned. Those projects that are proceeding have been reconfigured to capture CO2 and/or to produce multiple product streams—generally, power generation and/or urea for fertilizer production, and CO2 for enhanced oil recovery, such as is the case with the Texas Clean Energy Project. In the U.S. today, a primary interest is in waste gasification, as cities and towns seek to reduce the cost of disposing of municipal solid waste, reduce the environmental impacts of landfilling, and recover the energy contained in the waste. Although North America has generally turned away from new IGCC projects, IGCC projects are moving forward elsewhere; China’s 265-MW GreenGen project and the massive (2.6 GW available for export) Saudi Aramco Jazan refinery project are prominent examples.

Regional markets dictate which products will be most favorable in specific areas. Figure 4 provides an overview of regional market drivers and the products with the most potential to be economically desirable in the near term. Common traits mostly shared throughout India, China, and most of Southeast Asia are high natural gas prices and vast reserves of low-rank coal, which create a strong market for coal-derived substitute natural gas (SNG) facilities.

Figure 4. Gasification market drivers and products by region (figure courtesy of GE)

Figure 4. Gasification market drivers and products by region (figure courtesy of GE)

Although Figure 4 is based on the common belief that in the EU the potential for the expansion of gasification is limited, it actually could play a major role in reducing the reliance on imported natural gas.

Unquestionably, Asia is experiencing the strongest growth in coal and petroleum coke gasification (see Figure 5), with China leading the way. There are now a number of Chinese gasification technology companies that did not exist a decade ago. The high price of natural gas and LNG, coupled with LNG import restrictions in some countries in Asia (primarily China, India, Mongolia, and South Korea), are prompting those countries to utilize their domestic coal and petroleum coke to produce the chemicals, fertilizers, fuels, and power needed for their economies.

Figure 5. Gasification capacity by geographic region

Figure 5. Gasification capacity by geographic region4

Coal Is the Dominant Feedstock

Coal is the primary feedstock for gasification and will continue to be the dominant feedstock for the foreseeable future (see Figure 6). The current growth of coal as a gasification feedstock is largely a result of new Chinese coal-to-chemicals plants.

Figure 6. Gasification capacity based on primary feedstock

Figure 6. Gasification capacity based on primary feedstock4

Although there are many options for the feedstocks for gasification, coal is far and away the choice most often employed, for several reasons. Of course, energy security plays a role considering that coal is distributed globally. In addition, the price fluctuations in natural gas and LNG are another major concern. Figure 7 shows the price, in US$/MMBtu, of several fuel sources, including global oil, natural gas at two sites, and fuel oil, coal, and LNG in Asia over the decade from 2003 to 2013.

Figure 7. Recent prices for gasification fuel options (figure courtesy of GE)

Figure 7. Recent prices for gasification fuel options (figure courtesy of GE)

Fuel price volatility has affected industrial production of chemicals and other products for many decades. In the 1980s, volatile natural gas prices prompted Eastman Chemical Company to switch from natural gas to coal as a feedstock at their Kingsport, Tennessee, chemicals plant. Today, gasification project developers in Asia and elsewhere find themselves facing feedstock choices and fuel pricing options that can dictate project economics. Considering prices in Asia specifically (where most new large-scale gasification is taking place), oil, coal, natural gas, and LNG prices must be compared when considering new projects. In Asia, coal is by far the least expensive option. In addition, the price fluctuations for coal are relatively small compared to those observed in other fuel options.

Increasingly Larger Scale Plants

With a few exceptions, coal and petroleum coke gasification plants are becoming larger in scale to produce enough product(s) to meet market demand as well as to drive down the product price. Although the sizes of the gasifiers are not increasing substantially, the number of gasifiers per project is increasing. The increasing size of projects is resulting in the scale-up of the supporting equipment, such as the air separation units. Large gasification projects currently under construction or operating include:

  • Reliance Jamnagar Refinery (India): The world’s largest refinery and petrochemical complex will be gasifying petroleum coke and coal for the production of power, hydrogen, SNG, and chemicals. The project will have over 12 gasifiers and is currently under construction. The first gasification train is expected to be completed by mid-2015 and the overall project by early 2016.
  • Saudi Aramco Jazen Refinery (Saudi Arabia): This will be the world’s largest gasification-based IGCC power facility to convert vacuum residues to electricity for use both in the refinery and for export. This project is now selecting vendors and is expected to be completed in 2017.
  • Shell’s Pearl Facility (Qatar): The world’s largest natural gas-to-liquids facility using Shell’s gasification technology is now operational.
  • Tees Valley (England): The world’s largest advanced plasma gasifiers are being installed in the Tees Valley to gasify municipal solid waste, construction and demolition debris, and coal to produce power for an estimated 100,000 homes. This project is due to start up in 2016.

Remaining Challenges

Although the momentum behind the application of gasification has increased, a number of challenges remain to increasing deployment. One of the most important is a lack of regulatory certainty in some developing countries. For instance, some gasification projects in India are having trouble gaining a foothold amid concerns about feedstock availability and timely project approvals. Restrictions also are being created by some governments demanding that all technologies be domestically derived, slowing the advancement of deployment in the near term.

The upfront costs associated with large-scale gasification projects remain a hurdle today. Although alternatives to the capital-intensive projects exist, they are unlikely to become a suitable replacement for large gasification projects that offer a lower-cost end product and produce the large quantities of products necessary to meet market demand, such as the chemicals and fertilizer sectors. Bringing down capital costs or finding ways to obtain the required investment will remain a challenge.

Although the capital costs for gasification projects receive more attention, the industry is also working to find ways to reduce operating costs, often through efficiency improvements. For instance, the ability to remove contaminants from hot or warm syngas instead of first cooling the gas (for use with today’s commercially available processes) has the potential to yield significant energy savings. One promising project is RTI International’s warm syngas cleanup project.6 Research is also being undertaken on the development of sulfur-tolerant catalysts, which would allow the sulfur in the syngas to be removed at a later stage in the process, which may be more cost effective.

UCG is a promising technology that today remains relatively undeveloped. There are still technical challenges to UCG that must be overcome, but the major hurdles are actually institutional and a lack of public understanding. Successful demonstration projects could deter misconceptions that UCG is unproven and damages the environment. Linc Energy’s new UCG project in Poland will help demonstrate the viability of UCG to the world.

A great deal of innovative work is underway on new gasification technologies. In addition to UCG, a number of nontraditional approaches to gasification are emerging. For instance, KBR’s new TRIG™ gasification technology, the Free Radical Gasification (FRG™) technology developed by Responsible Energy, and the lower emissions gasification technology developed by ClearStack Power, LLC are all examples of the innovative work currently being conducted that will yield tomorrow’s gasification systems.


The gasification market has evolved significantly over the last five years. Coal gasification, and particularly coal gasification for power generation, has declined significantly in the U.S., although there is a growing interest in waste-to-energy gasification in North America.

Coal-based gasification (and coal gasification for chemicals) is dominant in Asia and will likely continue to be so for the foreseeable future. There is a growing market for petcoke gasification in Asia as well, as Asian refineries strive to remain competitive in the Asian market. High natural gas and LNG prices in Asia, the growing demand for energy and products in the developing world, and the need for energy security will all continue to drive the demand for coal and petroleum coke gasification.

These new plants are moving the deployment of gasification forward in a way that may not have seemed possible just 10 years ago. The tremendous amount of RD&D occurring globally promises that tomorrow’s technologies will be more advanced, less expensive, and more flexible than those in the market today. New experience, technical advancements, and the potential to integrate gasification with CO2 capture, combined with greater needs for energy security, may mean the coming years will fully unlock the potential for gasification that we’ve known has existed for decades.



  1. U.S. Energy Information Administration. (2013, 25 July). International energy outlook 2013: World energy demand and economic outlook,
  2. Williams, R. (2013). Coal/biomass coprocessing strategy to enable a thriving coal industry in a carbon-constrained world. Cornerstone, 1(1), 51–59.
  3. International Energy Agency. (2013, 12 November). World energy outlook 2013,
  4. Gasification Technologies Council. (2014). Database and library, (accessed July 2014).
  5. Higman Consultancy, GmbH. (2013). State of the gasification industry—The updated Worldwide Gasification Database. Presented at the 2013 International Pittsburgh Coal Conference, 1619 September 2013, Beijing, China.
  6. Research Triangle International. (2014). Warm syngas-cleanup technology, (accessed July 2014).


The author can be reached at


Gasification Fundamentals

Gasification is a thermal process that converts any carbon-based material, including coal, petroleum coke, refinery residuals, biomass, and municipal solid waste, into energy without burning it. The carbon-containing feedstock is reacted with either air or oxygen which breaks down the mixture into simple molecules, primarily carbon monoxide and hydrogen (CO+H2), called “synthesis gas” or “syngas”. The undesirable emissions from gasification can be much more easily captured because of the higher pressure and (often) concentration compared to conventional pulverized coal-fired power plants.


Gasifiers capture the energy value from coal, petroleum coke, refinery wastes, biomass, municipal solid waste, waste-water treatment biosolids, and/or blends of these materials. Examples of potential feedstocks that can be gasified and their phases include

  • Solids: All types of coal, petcoke, and biomass, such as wood waste, agricultural waste, household waste, and hazardous waste
  • Liquids: Liquid refinery residuals (including asphalts, bitumen, and oil sands residues) and liquid wastes from chemical plants and refineries
  • Gases: Natural gas or refinery/chemical off-gas

Gasifying Fluid

Gasifiers utilize either oxygen or air during gasification. Most gasifiers that run coal, petroleum coke, or refinery or chemical residuals use almost pure oxygen (95–99% purity). The oxygen is fed into the gasifier simultaneously with the feedstock, ensuring that the chemical reaction is contained in the gasifier vessel. Generally, gasifiers that employ oxygen are not cost effective at the smaller scales that characterize most waste gasification plants.


The core of the gasification process is the gasifier, a vessel where the feedstock(s) reacts with the gasification media at high temperatures. There are several basic gasifier designs, distinguished by the use of wet or dry feed, the use of air or oxygen, the reactor’s flow direction (up-flow, down-flow, or circulating), and the syngas cooling process. There are also gasifiers designed to handle specific types of coal (e.g., high-ash coal) or petcoke.

Prior to gasification, solid feedstock must be ground into small particles, while liquids and gases are fed directly. The amount of air or oxygen that is injected is closely controlled. The temperatures in a gasifier for coal or petcoke typically range from 1400° to 2800°F (760–1538°C). The temperature for municipal solid waste typically ranges from 1100° to 1800°F (593–982°C).

Currently, large-scale gasifiers are capable of processing up to 3000 tons of feedstock per day and converting 70–85% of the carbon in the feedstock to syngas.


Although syngas primarily consists of CO+H2, depending up on the specific gasification technology, smaller quantities of methane, carbon dioxide (CO2), hydrogen sulfide, and water vapor could also be present. The CO:H2 ratio depends, in part, on the hydrogen and carbon content of the feedstock and the type of gasifier. This ratio can be adjusted or “shifted” downstream of the gasifier through the use of catalysts. Ensuring the optimal ratio is necessary for each potential product. For example, refineries that produce transportation fuels require syngas that contains significantly greater H2 content. Conversely, a chemicals production plant uses syngas with roughly equal proportions of CO and H2. This inherent flex-ibility of the gasification process means that it can produce one or more products from the same process.

Some downstream processes require that the trace impurities be removed from the syngas. Trace minerals, particulates, sulfur, mercury, and unconverted carbon can be removed to very low levels using processes common to the chemical and refining industries.



Most solid and liquid feed gasifiers produce a glass-like byproduct called slag, composed primarily of sand, rock, and minerals contained in the gasifier feedstock. This slag is nonhazardous and can be used in roadbed construction, cement manufacturing, and in roofing materials.

Underground Coal Gasification

With underground coal gasification (UCG), the actual gasification process takes place underground, generally below 1200 feet in depth, although recent advances in well-drilling technologies now make UCG possible at much deeper conditions (i.e., 4000–6000-ft depth range).

The UCG reactions are managed by controlling the rate of oxygen or air that is injected into the coal seam through the injection well. The process is halted by stopping this injection. After the coal is converted to syngas in a particular location, the remaining cavity (which will contain the leftover ash or slag from the coal, as well as other rock material) may be flooded with saline water and the wells are capped. However, there is a growing interest in using these cavities to store CO2 that could be captured from the above-ground syngas processing or even nearby combustion facilities. Syngas from UCG can also be treated to remove trace contaminants; once CO2 storage is added, UCG offers another opportunity to achieve a coal-based, low-carbon source of energy and carbon-based products. Once a particular coal seam is exhausted (after up to 15 years), new wells are drilled to initiate the gasification reaction in a different section of the coal seam.

UCG operates at pressures below that of the natural coal seam pressure, thus ensuring that materials are not pushed out into the surrounding formations. This is in contrast to hydraulic fracturing operations in oil and gas production, where pressures significantly above natural formation pressure are used to force injectants into the formation.


As explained, gasification can be used to yield a number of carbon-containing products, including several simultaneous products at polyproduction facilities.

Gasification is a complex process with decades of development behind it. The future of gasification technologies promise to improve on the work that has already been done.

For more information on gasification, visit the Gasification Technologies Council website:

The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.