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Coal-Fired Power Generation in Japan and the World

By Sumie Nakayama
Senior Advisor on Climate Change, J-POWER

The Japanese government set its 2030 power generation target shares for coal at 26%, nuclear at 22%, and gas at 27%. Due to concerns over the slow restart of nuclear power generation, the power sector’s interest in building more efficient coal-fired power generation facilities with low CO2 emissions is increasing. This article examines the reasons behind Japan’s energy policy and the choice of coal. In addition, it looks at the importance of coal for the future of Asian countries and the ways in which Japan is contributing to clean coal technologies both domestically and internationally.


Historically, Japan’s use of energy resources for power demand and supply has experienced two major changes, as depicted in Figure 1. One is the gradual reduction of oil dependence in 1970–2010 and the other is the dramatic disappearance of nuclear after 2011. The heavy dependence on oil (around 70%) in the 1970s risked Japan’s energy security with the oil crisis. Consequently, a new and stronger energy policy was implemented to reduce dependence on oil by promoting coal, liquefied natural gas (LNG), and nuclear power. The result of this diversification reduced oil dependence from around 70% to 8% by 2010 (red bar in Figure 1). However, the major earthquake coupled with the disaster at the Fukushima Daiichi nuclear power plant in 2011 cast a huge shadow over Japan’s energy scene and resulted in major changes. All 54 nuclear reactors in Japan were shut down. In 2012, Japan established a new safety institute, the Nuclear Regulation Authority (NRA), following the introduction of the most stringent new safety standards in the world, which must be implemented before a nuclear reactor can restart.

FIGURE 1. Historical trend of Japan’s power generation portfolio, 1970–2014, and 2030 target.1,2

In 2015, the Japanese government set a new energy policy that includes a 2030 energy supply-and-demand target.1 The policy was developed to balance energy security, economy, environment, and safety. The power generation national targets set for 2030 are nuclear 22%, coal 26%, LNG 27%, oil 3%, and renewables 22%. Coal-fired power will contribute 56% to the baseload, as the government aims to ensure around 60% baseload for stable supply, together with nuclear, hydropower, geothermal, and biomass.

The modern, efficient, and low-emission Isogo Power Station.

To date, restarting the existing nuclear reactors has taken longer than anticipated. With the permanent shutdown of six reactors at Fukushima Daiichi and five other older reactors, there are now 43 potential reactors that could become operational again. An assessment to meet the new nuclear standard requirements can take up to two years. The NRA has assessed 26 reactor submissions. To date, only five reactors have passed assessment. Due to the extended time it was taking to restart the reactors, several regional power utilities were encouraged to find alternatives to increase baseload power generation. In addition, ongoing deregulation of the power market has encouraged new power generators to utilize more cost-effective power sources. As a result, several new coal-fired power generation projects are being planned, with some already under construction. Figure 2 depicts the breakdown of Japan’s installed power generation capacity by energy source. Coal-fired power generation capacity is 40 GW, accounting for 16% of the total.

FIGURE 2. Power generation capacity by energy source in Japan, 2014.2

The main owners of Japan’s coal-fired power plants are 10 regional power utilities and J-POWER. Figure 3 depicts the total coal-fired power generation capacity in Japan and the share held by different companies.

FIGURE 3. Owners of coal-fired power plants in Japan, 2014.3

J-POWER was established in the 1980s as a state-owned power wholesaler and has promoted imported coal-fired power generation in accordance with government policy. It is the largest coal-fired power plant operator in Japan.

Coal and nuclear are considered the best options for baseload power generation in Japan because it is less expensive than gas. Gas imported as LNG has a high price due to the liquefaction cost and the additional freight cost. According to the International Energy Agency, the relative price of coal to gas differs in the U.S., Europe, and Japan.4 In the U.S., coal is almost equivalent in price to gas for electricity generation, whereas the price of coal in Japan is substantially lower than gas.

Before the Fukushima disaster, no new coal-fired power projects had been built in Japan in the 21st century. All the environmental impact assessments (EIAs) for coal-fired power projects were rejected by the Ministry of Environment (MoE) because they would increase CO2 emissions in Japan. However, after the shutdown of all nuclear power reactors, serious concern developed about a power shortage in the Greater Tokyo area, which resulted in a call for tenders from the Tokyo Electric Power Company (TEPCO) for 2.6-GW baseload power generation. But bidders were reluctant to make detailed bids for coal-fired projects because the MoE would block any coal project in the EIA process even if it won the tender. This obstacle concerned the Ministry of Energy, Trade and Industry (METI), which is responsible for management of energy demand and supply in Japan.

To eliminate concern among potential bidders about the MoE’s hostility to coal-fired power generation, METI and the MoE made an agreement. If new fossil-fired power projects met two conditions, MoE would not block the project in the EIA process, so that companies could submit a tender to TEPCO without fear of being rejected. The first condition is to use the best available technologies (BAT); thus only ultra-supercritical (USC) technologies were eligible. The other condition is that the power sector established a coalition with a targeted emissions cap which is consistent with the government’s 2030 energy mix and CO2 emissions targets—and the CO2 emissions from the approved project must be within the cap. The MoE published the energy efficiency standard required to be met by potential bidders in a table by fuel type (coal and gas) and by plant size.5 For example, a 1000-MW coal-fired power plant must achieve 45% (LHV, gross) energy efficiency.

Currently, 17 GW of new coal-fired power projects are at various stages of development in Japan, ranging from the early stage of the EIA process to being constructed.6 All the large-scale projects plan to use USC technology to meet government conditions. The proposed coal-fired power projects include small power projects without USC as USC is not suitable for smaller size coal-fired power plants. As an alternative for smaller projects, co-firing of biomass fuel is used to reduce CO2 emissions.

In February 2016, due to the MoE’s concerns about the increasing number of new projects, METI announced amendments to two existing laws. One amendment regulates power generators to achieve energy efficiency standards consistent with the 2030 national target; the other regulates power retailers in procuring a share of non-fossil power consistent with the 2030 national target.

Both regulations allow “collective action” to achieve the goal. The 35 main players in the power sector have formed a framework to achieve the goal collectively.

In May 2016, the Oxford Smith School of Enterprise and Environment published a report, “Stranded Assets and Thermal Coal in Japan: An Analysis of Environment-Related Risk Exposure”.7,8 The report concluded that the new coal fleet investment of US$6-8 billion would result in a stranded asset in 5–15 years. However, several of the assumptions in the report were incorrect.8 First, the number of coal-fired power projects was exaggerated; the Oxford paper assumes 28 GW while the Japanese government says a maximum of 17 GW of coal-fired power will be built. The Oxford paper also names eight new J-POWER projects: Takehara, Takasago, Nishiokinoyama, Osaki Coolgen, Kashima Power, Yokohama, Shin Yokosuka, and Yokosuka. However, three of them—Yokohama, Shin Yokosuka, and Yokosuka—are not J-POWER’s projects.

The biggest problem with the Oxford paper, as noted by Professor Arima,8 is its failure to consider Japan’s energy policy and 2030 national targets. It also fails to consider Japan’s energy security or economy, focusing only on the environment. The study assumes that coal-fired power generation is hazardous for human beings and does not recognize that Japan requires stable and cost-effective power generation. Moreover, the new coal-fired power plants will use the most advanced clean coal technology, which will remove SOx, NOx, and particulate matter (PM) at a nearly 100% rate (depending on the coal’s characteristics). CO2 emissions will also be reduced through high-efficiency plants and through use of CCS in the future.

Japan is a world leader in USC technology for clean coal technology and continues to make further improvements through R&D. As a result, Japan has built coal-fired power plants achieving low emissions. J-POWER’s Isogo Power Station demonstrates Japan’s best clean coal technology, with an efficiency of 45% (LHV, gross), reduced flue gas, single-digit ppm SOx, less than 10 ppm NOx , with PM less than 5 ppm at the stack.

Inside Isogo coal-fired power plant.

Located in Yokohama, the second largest city in Japan by population, Isogo Power Station is only 6 km from Yokohama’s city center and 30 km from central Tokyo. It is a unique, urban coal-fired power station that employs some of the most advanced clean coal technologies in the world.

Originally, Isogo Power Station had two 265-MW subcritical boilers. The old station started commercial operation in the 1960s, and had been supplying baseload power for more than 35 years. In 1996, the government approved a replacement plan. As a result of discussion with the buyers and Yokohama City, the new station was designed to have 2 units of 600 MW with the world’s highest energy efficiency and lowest emissions for a coal-fired power station. The boilers and turbines use USC technology with a main steam temperature/pressure of 600°C/25 MPa and a reheat steam temperature of 610°C. The plant uses a dry-type DeSOx system to reduce emissions.

Figure 4 shows that SOx and NOx emissions from Isogo are less than those from fossil-fired power plants in other developed countries, due to this advanced DeSOx and DeNOx system.

FIGURE 4. Japan has some of the lowest SOx, NOx per thermal-power-generation electric energy in the world.9–11

Currently, J-POWER and Chugoku Electric Power are conducting R&D on oxygen-blown integrated coal gasification combined cycle (IGCC). The aim is to improve energy efficiency and develop economic CO2 capture from syngas, and A-USC to further increase efficiency and reduce CO2 emissions. The goal for commercialization of IGCC is the early 2020s; then triple combined-cycle technology also employing fuel cells and integrated coal gasification fuel cell combined cycle (IGFC) is the next R&D step to improve energy efficiency further. Japan intends to remain a world leader in clean coal technologies. It is important to allocate sufficient budget and invest in innovative technologies wisely.


According to the IEA, in 2014, coal provided 40% of the world’s power generation—the largest share. Historically, in the 1990s the OECD’s share in coal-fired power generation was 70%, as depicted in Figure 5. The volume of coal-fired power generation has more than doubled since then and is expected to grow 24% by 2040. The share of non-OECD’s coal-fired power generation began to accelerate in 2000 and, at current levels, is expected to be more than 60% today and will be more than 80% in 2040. Coal demand in the Asian power sector will increase by 67% from today to 2040.

FIGURE 5. Cumulative capacity of retired and added coal-fired power plants by region, 2015–2040.5

Figure 6 shows the cumulative capacity of retired and added coal-fired power plants by region between 1990 and 2040. In OECD countries, the total retirement of coal-fired plants is more than 300 GW, whereas total additions are 100 GW. In China and Southeast Asia, a large number of additional coal-fired plants is expected to be built. According to the IEA, between 2015 and 2040 the total additional capacity of coal-fired power plants in non-OECD countries will be more than 1000 GW, or more than half of the existing capacity of coal-fired plants in the world.

FIGURE 6. Coal-fired power generation, 1990–20404,11

Countries are building coal-fired power generation primarily because coal is an inexpensive power source in comparison to other energy sources. Many of those countries, such as China and Indonesia, also have large reserves of coal. Many of the economic growth plans of non-OECD countries are built around an energy policy based on inexpensive coal-fired power. Therefore it is important to encourage use of coal in the most efficient way—that is, through high-efficiency power generation technology in order to reduce CO2 emissions—particularly in non-OECD Asia.

In the wake of increased awareness about the risks of climate change, criticism of coal is increasing in OECD countries. In addition, public financing for new coal-fired power projects is being restricted. An agreement was reached after several months of intense argument over a proposal by the U.S. and the UK to ban all public financing of coal-fired power projects and a counter-proposal by Japan and Australia to allow efficient coal-fired power projects, with high-efficiency technology to be eligible. In September 2015, the OECD’s Export Credits Arrangement review process was changed to allow investment in coal-fired power projects that employ USC technology. OECD member countries accepted that efficient use of coal helps non-OECD countries reduce CO2 emissions effectively, instead of banning officially supported export credits to all coal-fired power projects.

Given the need for efficient use of coal in Asia, Japan intends to encourage and deploy its clean coal technologies in countries to effectively mitigate global CO2 emissions. J-POWER is engaged in several projects in Indonesia, including construction of two IPP 1000-MW USC coal-fired units in Central Java. The project will use local subbituminous coal and be Indonesia’s first coal-fired power plant to use USC technology. The plant is expected to become operational in 2020. The project will also contribute to the sustainable development of Indonesia and CO2 mitigation.


The Paris Agreement went into force in November 2016 under the United Nations Framework Convention on Climate Change (UNFCCC). To achieve CO2 emissions reduction targets, countries will need to implement a wide array of mitigation technologies, including clean coal technologies. In the short term, efficient use of coal is the key to CO2 emissions reductions in Asian countries. Japan’s clean coal technology will contribute to using coal most efficiently in power generation and support sustainable development in Asia. J-POWER is engaged to demonstrate and implement clean coal technologies commercially both in Japan and internationally and to continue with further research and development.


  1. Ministry of Energy, Trade and Industry of Japan. (2015, July). Long-term energy supply and demand outlook 2015,
  2. Ministry of Energy, Trade and Industry of Japan. (2016). Energy white paper 2016 [in Japanese],
  3. The Japan Electric Association. (2015). Electric power industry handbook [in Japanese]. Tokyo: Ohmsha.
  4. International Energy Agency (IEA). (2015). World energy outlook 2015. Paris: OECD/IEA.
  5. Ministry of the Environment of Japan. (2014). BAT reference table [in Japanese],
  6. Ministry of Energy, Trade and Industry of Japan. (2016). Document 1 of the Third Meeting of Working Group on Standard and Criteria of Thermal Power Generation [in Japanese],
  7. Caldecott, B., Dericks, G., Tulloch, D.J., Kruitwagen, L., & Kok, I. (2016, May). Stranded assets and thermal coal in Japan: An analysis of environment-related risk exposure. Smith School of Enterprise and the Environment, University of Oxford,
  8. Arima, J. (2016). Some doubts about Oxford’s argument on stranding thermal coal in Japan [in Japanese]. The University of Tokyo,
  9. Federation of Electric Power Companies. (2015). FEPC Electricity Infobase h-6 Environment and energy [in Japanese],
  10. J-POWER. (2016). J-POWER Group sustainability report 2016,
  11. IEA. (2014). CO2 emissions from fuel combustion 2014 (CD-ROM). Paris: OECD/IEA.


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Solving Energy Poverty, Unemployment, and Growth Challenges in South Africa

By Rob Jeffrey
Senior Economist and Managing Consultant, Econometrix (Pty) Ltd


The three fundamental objectives of South Africa, and most emerging nations, are to address inequality, unemployment, and poverty. These objectives cannot be achieved by redistribution of wealth alone. They can only be achieved by raising the economic growth rate. A higher growth rate is dependent on having the correct public policies in place and having an adequate and growing supply of affordable electricity. In order to ensure economic growth, South Africa must develop its industrial base and therefore it is essential to supply electricity at the lowest possible cost.


In South Africa the major electricity supply company is Eskom. The major issue raised by Eskom executives in this debate concerns renewables. They have accurately described the fallacy and weakness of the primary renewables, wind and solar. These are highly variable, often supplying power when they are not needed and not supplying power when they are needed.1 As a result, these are expensive forms of energy production, yet the supply must be bought in terms of the purchase agreements at set prices. This has been the experience of Germany (under the “Energiewende” program) where the country sells unwanted electricity at a loss to other countries and purchases the required supply at a premium. These prices are in effect financial subsidies for wind and solar.

Cape Town city lights coming on at dusk.

In Germany, they are fortunate that they have other major electricity-generating countries nearby; they can tap into electricity provided by nuclear power plants in France, coal-generated electricity in Poland, or hydro-electricity from Scandinavia. South Africa does not have that option. Due to these financial subsidies, Germany, aside from Denmark, has the most expensive industrial and household electricity in Europe. Consequently, Germany has now placed a cap on the supply of renewables and is in the process of removing all financial subsidies to renewable companies.2 What “energiewende” has clearly established is that wind energy and solar CSP are not technologies suitable for mass baseload electricity supply.3 This theme has been repeated in other countries such as Australia where their wind energy drive is a case in point and echoes what has happened in Germany.4

The drive for “green energy” is slowing growth and enforcing poverty in emerging economies. In developed economies, it is causing unemployment, reducing living standards, and increasing energy poverty. This can be seen in the political backlash in Britain, the U.S., and even Germany. In these nations, affluent environmentalists argue that the cost is merited. They have the ear of financial institutions and governments. The institutions see secure profits because of guaranteed prices and subsidies, and governments can afford the subsidies because there are limited objections to “green” taxes. Green taxes can become a regressive tax with people on lower incomes having to pay relatively more than people on higher incomes. Consequently, renewables are in effect a tax on the poor.

In South Africa, concerns exist over plans to introduce massive windfarms totalling 60 GW spread across South Africa. It is deemed that geographically separated windfarms will ensure a more continuous supply of electricity.5,6 A wind profile study has been conducted across the country. This theoretical study held the view that somewhere in the country, the wind is blowing. This is not the experience of Europe and the UK where the average load factor from all onshore windfarms remains 30% or less.7 Electricity generation would still need to have back up for baseload power when delivery fails. As set out by the Council for Scientific and Industrial Research (CSIR), a full delivery plan for 16 GW of baseload electricity requires a total of 60 GW energy capacity consisting of onshore facilities (offshore windfarms have not yet been considered, as they are far too expensive) of 32 GW wind, 12 GW solar PV, and 16 GW of gas for consistent secure delivery of electricity. This full delivery plan for 16 GW baseload power would require more than 6000 km2 of unsightly windfarms generally built on high ground to ensure maximum efficiency. More than 12,000 km of roads will be needed to service all the units and the landscape of the countryside would be criss-crossed by at least 10,000 km of additional transmission lines. They would also damage the local habitat, with extensive evidence from other windfarms of mortality to insect, bird, bat, and other flying life that are particularly vulnerable to windfarms. Windfarm developers in the planning stages must take adequate preventative provisions and actions to avoid habitat, ecological, and environmental problems.


The second major issue raised by Eskom concerned nuclear. The CEO of Eskom stated that baseload electricity should be provided by coal (presumably including other fossil fuels, primarily gas) and nuclear. The question remains, how much nuclear? Nuclear power stations can take up to 10 years and longer to build, and the upfront costs make a large build program unaffordable for a country such as South Africa. As an example, Britain recently approved the construction of the Hinckley Point nuclear power station project. The total cost for the 3200-MW Hinckley Point nuclear power station could be US$30 billion. In comparison, the new 4800-MW Medupi coal-fired power station costs an estimated US$14 billion and the initial, now installed, renewables 2310-MW program cost approximately US$12 billion.

Coal-fired power stations provide most of South Africa’s electricity.

Renewables in South Africa only have a load factor or deliver power 31% of the time,8 their total cost exceeds nuclear with load factors of 92% while clean coal-fired plants such as Medupi with load factors of 85% are far less expensive. Renewable capital costs have dropped substantially since 2011 and are currently far below the initial costs as set out above. The guaranteed delivered costs for wind-generated electricity are approximately 62 cents/kWh. A first assessment would indicate that wind is cheaper than its coal and nuclear competitors. However, based on this guaranteed delivered price and a load factor of only 31%, this guaranteed price effectively becomes a subsidized price as it is paid for whether the electricity is required or not. There are also increased costs due to a low load factor on transmission costs, and furthermore, greater distances are involved. As a result, the true total cost of wind power as a deliverable baseload dispatchable power source is significantly more expensive than coal-generated electricity. The cost is also greater than nuclear which, in turn, is also approximately 30% more than equivalent coal-fired electricity.

These significantly higher final delivered electricity prices would have a major detrimental impact on the economy. Increased electricity costs would slow economic growth and devastate the goods-producing industries—in particular, the key mining, manufacturing, agricultural, and agro-processing industries. These industries are important to South Africa’s export performance and employment growth, particularly among the relatively unskilled work force. By 2030, it is estimated that there will be 16 million new workers entering the work force. With low baseload electricity growth of only 2.5% per annum, due to the planned heavy reliance on renewables unsuitable for baseload power, GDP growth is unlikely to increase at more than approximately 2.8% per annum. At this growth rate, fewer than 6 million jobs will be created by 2030, resulting in unemployment growing by at least 10 million job seekers.9


The third major issue raised concerned the role of Independent Power Producers (IPPs). The point made was that Eskom would no longer sign new agreements with IPPs.10 According to Eskom, the issue concerned the guaranteed prices and offtakes of renewables, not the IPPs themselves. It would be uneconomic for Eskom to pay guaranteed prices without assurance that electricity would be delivered. This is economically, and from a business perspective, absolutely correct and there is now concern about the future role of IPPs. However, IPPs are essential for the future of energy provision and economic development of the economy.

Eskom is already a giant monopoly controlling generation, transmission, and distribution of the entire market, which cannot be allowed to continue in a market-orientated economy. Eskom generates, distributes, and controls through the grid close to 40,000 MW. By 2035, in less than 20 years, South African electricity demand is expected to increase to over 70,000 MW. The bulk of this electricity growth should be provided by IPPs to ensure a more competitive power market.

The existence of a mega-monopoly, whether state-controlled or privately owned, prevents competition and will affect negatively on the economy. The structure of Eskom in this process must be addressed. Eskom, one of the largest electricity utilities in the world, should be split into at least two, and preferably three, stand-alone independent operating companies: a generation company (Genco), a company responsible for the grid transmission and market operations (Gridco), and a distribution company (Disco).

Internationally, countries are increasingly privatizing and deregulating their electricity sectors to ensure more efficient management. The three companies, Genco, Gridco, and Disco, should be set up as three independent public-private partnerships with management firmly in the hands of the private sector. Genco would focus on baseload generation, replacing its aging fleet using clean coal technologies supported by major gas operations. This structure would allow the IPPs to flourish and bring in genuine competition free of all subsidies. This must include all generating, grid, and distribution subsidies. If subsidies are required, for example to encourage distribution and poverty alleviation, these must be government funded not company funded. Some difficult political decisions would need to be made in a transparent way.


The fourth major issue in the background of every decision regarding energy is climate change and the commitment to COP21. The outcome of COP21 was the Paris Agreement. What was important was not only what was agreed but more importantly what was not agreed.

Governments were able to negotiate a set of sound long-term global objectives. The Paris Agreement reflects a “hybrid” approach, blending bottom-up flexibility (to achieve broad participation) with top-down rules, to promote accountability and ambition.11 Importantly, the agreement asked for no firm commitments by any country. Many provisions establish common goals while allowing flexibility to accommodate different national capacities and circumstances. The reason for an objective or goal without binding obligations was simply that various countries were unable to reach national political agreement internally (e.g., the U.S.). Emerging countries were also not going to make firm commitments as they had other priorities such as high levels of poverty and/or had rich fossil fuel reserves. In summary, countries were expected to do what was in their best economic and financial interests. This is and needs to be exploited by all emerging economies with high levels of poverty and with extensive, relatively cheap fossil fuel resources.


The emerging countries include the ASEAN countries, China, Russia, India, Vietnam, Korea, and Poland. Many of these countries are embarking on major expansions of coal and fossil fuels. They have determined that clean coal and gas are the cheapest, most efficient, and reliable sources of electricity to achieve their economic growth objectives and, in turn, poverty reduction, with replacement of aging inefficient power stations a major objective. Clean coal is globally recognized to be a cost-effective and efficient method of reducing emissions and reducing other pollution.12

The 10 ASEAN countries are prime examples of countries using clean coal technologies. In these countries, electricity generation increased by an average of 7.5% per year, from 155.3 TWh in 1990 to 821.1 TWh in 2013. Fossil fuels generated 79.4% of ASEAN electricity in 2013. Coal-based electricity capacity is projected to increase from about 47 GW in 2013 to 261 GW in 2035, an average growth rate of 8.1%.13 In Vietnam, GDP growth is expected to average 6% per annum between 2015 and 2030. Coal generation will increase from 36% of electricity generation to 56%, increasing at 7.2% per annum.14 All these countries are expecting annual growth of over 5% for the next 15 years. South Korea expects growth in its power sector of 3.6%, the major proportion of which will be coal and gas.15 In Poland, electricity growth is also expected to be primarily coal-based generation.

Piyush Goyal, Minister of State with Independent Charge for Power, Coal, New and Renewable Energy in the Government of India, has stated, “We will be expanding our coal-based thermal power. That is our baseload power. All renewables are intermittent. Renewables have not provided baseload power for anyone in the world.”16 It is not surprising, therefore, that in India annual average electricity demand between 2000–2013 grew from 376 TWh to 897 TWh, most of it coal based. Coal-fired electricity is forecast to grow at over 4% per annum from approximately 166 GW to 500 GW by 2040.17

Cape Town settlement.

In comparison, the average growth in “Electricity available for distribution in South Africa” as measured by StatsSA grew an average of only 1.7% during 1990 and 2015.18 Average GDP growth was 2.5% during the same period. Even worse, average electricity demand growth from 2000 to 2015 has averaged only 1.3% per annum. Over this period, the average GDP was 3.1% per annum.19 This higher economic growth was due to excessive growth in the services sector, primarily in the public and government sectors, not from the mining and manufacturing sector where growth was poor. The equivalent figures for the period 2008 to 2015 were electricity supply growth of only approximately 1.1% per annum and GDP growth of only 1.9% per annum. It is little wonder that South African GDP growth does not parallel other high-growth emerging economies. In terms of the IRP, electricity growth between 2015 and 2030 appears to be approximately 3.9%.20 However, because of the low load factors of renewables, real deliverable baseload electricity growth could be only 2.5% per annum. As a result, future average growth to 2030 is unlikely to average more than 2.8% per annum.20


South Africa is facing slow growth and lack of both domestic and foreign investment primarily in the mining and manufacturing industries. From a policy point of view, public policies need to change radically to make South Africa (a treasure chest of coal and minerals) attractive to such investment again. Planning for low baseload electricity growth is a self-fulfilling prophecy. Industrialized countries and their leaders need to recognize that the needs and requirements for emerging and developing economies are independent from their own with different priorities such as poverty alleviation.

Emerging markets need secure baseload electricity power at the lowest possible cost to give them a comparative economic advantage, whether that natural resource is oil, hydroelectricity, or a fossil fuel such as coal or gas. The developed world needs to recognize that, at this stage of technological development, fossil fuels in the form of gas and coal will continue to play a substantial role in providing the country’s major energy source. In a speech earlier this year, President Obama acknowledged that emerging economies such as India, China, and the ASEAN countries would be building coal-fired power stations out of necessity, but advised they should use clean coal technology.21

It is time for South Africa to break away from the vested idealistic or financial interest driving the large renewable expansion schemes. They are not the panacea for the country’s future energy problems and growth. Nuclear and coal are the only sources of energy that can provide security of baseload electricity supply at internationally competitive prices. The fact that nuclear is capital-intensive upfront means that South Africa cannot afford a major investment in nuclear as the way forward. Nevertheless, if procurement goes ahead, it should be no more than a maximum of 3200 MW. The way ahead for South Africa lies in limited nuclear build, major new build, and replacement of relatively older coal-fired power plants with new clean coal power generation supported by major expansion of gas plants. It should be made mandatory to install solar PV on all new domestic houses and all business buildings. Tax incentives should be available to install solar PV on new and existing structures.


The South African economy cannot afford to restructure its economy and industry toward renewable energy nor can it afford the other structural changes this implies, including any form of carbon tax, either now or in the foreseeable future. Such a move will only increase uncertainty and further reduce long-term domestic and foreign investment. Carbon tax and massive renewable policies are poised to take South Africa in the wrong economic direction resulting in slow economic growth and increased unemployment. This will have major detrimental economic, political, and social consequences affecting the country for a generation.

The cost and burden of such plans always fall on the poor in terms of high unemployment, regressive taxation, and increasing poverty. South Africa already has these problems and needs to follow the lead of other emerging nations that are increasingly using coal and gas to pursue higher growth. Energy, electricity, and employment growth are the keys to South Africa’s future economic, social, and political prosperity, sustainability, and stability. It is time to put South Africa first.


  1. Eskom Media Statements. (2016). Various,
  2. Horgan, J. (2016, 7 July). Germany’s energiewende sticks it to the poor. The American Interest,
  3. Andrews, R. (2016, 22 August). An update on the energiewende. Energy Matters,
  4. Sloan, J. (2016, 19 July). Energy price reveals folly of renewables. National Wind Watch,
  5. Bofinger, S., Zimmermann, B., Gerlach, A.-K., Bischof-Niemz, T., & Mushwana, C. (2016, 3 March). Wind and solar PV resource aggregation study for South Africa. Public presentation of results. Pretoria: CSIR and Fraunhofer.
  6. World Nuclear Association. (2016, September). Renewable energy and electricity,
  7. Eskom. (2016, 31 March). Integrated report,
  8. Econometrix in-house analysis
  9. Eskom Media Statements. (2016).
  10. Bodansky, D. (2016, 17 May). The Paris climate change agreement: A new hope. American Journal of International Law, 110 (forthcoming). Available at:
  11. Sporton, B., (2016, 30 March). The power of high-efficiency coal. World Coal Association,
  12. Suryadi, B, & Velautham, S. (2016, 9 June). Coal’s role in ASEAN energy. ASEAN Centre for Energy,
  13. World Coal Association (WCA). (2016, 15 March). Coal in the energy mix of Vietnam,
  14. Siemens. (2013). South Korea: A paradigm shift in energy policy,
  15. WCA. (2016). Energy in India. WCA,
  16. WCA. (2015). India’s energy trilemma,
  17. Statistics South Africa. (2016). Electricity generated and available for distribution: July 2016,
  18. South African Reserve Bank. (2016). Full quarterly bulletin, No. 281, September 2016,
  19. Department of Energy, Republic of South Africa. (2013, 21 November). Integrated Resource Plan for Electricity (IRP) 2010–2030. Update report 2013,
  20. Econometrix in-house analysis
  21. Martin, R. (2016, 9 June). Modi and Obama shake hands, but India’s path to clean energy remains long. MIT Technology Review,


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The Challenges for CCS

By Tony Wood
Grattan Institute

Any hard-nosed assessment of the energy sector should conclude that there is no future for coal without carbon capture and storage (CCS). Yet for the last decade, governments, their agencies, and the coal industry have failed to support CCS development in a way that would be consistent with this existential threat. The result is that CCS has little credibility as a material contributor to reducing emissions with governments and those outside the fossil fuel industry. This is despite projections by reputable bodies such as the International Energy Agency (IEA) that show CCS does make a material contribution to delivering a low-emissions future at lowest cost. The prospects for bridging that gap rests with several demonstration projects or a major mobilization by a country such as China.


Reducing greenhouse gases and particularly carbon dioxide (CO2) is at the heart of the global commitment to addressing climate change. That means we either stop burning fossil fuels or prevent the CO2 from entering the atmosphere, or both. Neither is simple or cheap.

Hydropower, wind, and solar energy are making a significant and growing contribution to the former approach, although hydro is constrained by available sites, while wind and solar need major progress on storage technologies to get to the majority side of the supply ledger. Nuclear energy remains either too expensive or politically unacceptable in many parts of the world.

Reducing CO2 is the key to addressing climate change.

Attempts to turn CO2 into a solid material through mineralization have generally proven to be expensive or not scalable. Capturing and permanently storing the CO2 underground remains a tantalizing prospect that could significantly contribute to reductions in greenhouse gas emissions, while allowing the ongoing use of fossil fuels, coal and natural gas, for decades into the future. At the least, this prospect would allow us more time to develop cost-effective alternatives.

For most of the current century, the cost of wind and solar power has fallen as their deployment has grown. Government support through policies such as renewable portfolio standards and mandated targets or attractive feed-in tariffs have driven this growth in many countries. Actual deployment has consistently exceeded the projections of the most well regarded bodies such as the IEA, and this story has yet to reach an end. Yet the same agencies have consistently projected deployment of CCS that has turned out to be highly optimistic.

The IEA’s most recent World Energy Outlook1 includes a 450 Scenario that depicts a pathway to the 2°C climate goal committed to by the international community and reaffirmed as a minimum target in the Paris Agreement of December 2015. Under this scenario, the IEA’s analysis indicates that coal consumption will begin to decline from before 2020 and that, by 2040, coal accounts for only 16% of the world’s energy mix. Further, even the 12% of electricity output that is based on coal in this scenario depends on CCS for three-quarters of its produced power. With only one such operational plant in the world to date, and a couple close to commissioning, that projection seems a distant prospect.

Few governments have adopted policies over the last decade or so that would drive CCS development and deployment, and few show any appetite to do so today. The most common reaction from political leaders and energy industry executives is that CCS does not work, is untested, or is just too expensive to be taken seriously. The fossil fuel industry has consistently failed to mobilize financial or political support to counter this perception. Only a handful of demonstration projects have progressed beyond the drawing board, at the same time as supporters of renewable energy have successfully lobbied for large and ongoing government subsidies.

There is a little progress with the development of CCS, despite international organizations such as the IEA publishing forecasts about the key role CCS could play in reducing CO2 emissions and calls for governments to fund demonstration projects. CCS faces significant hurdles: the high costs that were associated with wind and solar a decade ago; capital intensity, shared by nuclear power, that creates high financial risk; and widespread opposition by environmentalists as a smokescreen to extend the life of fossil fuels when they should be confined to history. Its friends are few. So, where or what might give rise to change?


Growth in energy demand has been the central impetus behind increasing global greenhouse gas emissions for many decades. Decoupling of energy consumption from economic growth, together with low economic growth across the developed world, has constrained the need for large-scale energy production. Things have been different in developing economies. The People’s Republic of China (PRC) has been a major driver of increasing emissions this century, and its actions will be critical if climate change is to be effectively addressed. The PRC has ratified the Paris Agreement and is making progress toward a national emissions trading scheme as a central policy response. Even with lower economic growth in very recent years, the PRC continues to need more energy. Further, CO2 emissions from industrial production outside the power generation sector are major source of emissions for the PRC, and for which wind and solar do not provide a solution.

It the COP21 meeting in Paris, the PRC’s National Development and Reform Commission (NDRC) and the Asian Development Bank launched a CCS Roadmap2 that incorporates policy, legal, technology, financial, and public engagement as an integrated approach to CCS for the PRC. It demonstrates that CCS can contribute to meeting the country’s emissions reduction targets in the short, medium, and long term through specific actions during the period of the 13th Five-Year Plan and beyond 2020. The key messages in the Roadmap are:

  • CCS demonstration and deployment is essential for cost-effective climate change mitigation, not only in the power sector, but also for reducing emissions in carbon-intensive coal-chemical, steel, cement, and refinery plants.
  • The PRC can benefit from international experiences.
  • Unique low-cost CCS demonstration opportunities exist in the PRC, most notably in regions that offer prospects for CO2 capture from coal-chemical plants and enhanced oil recovery.
  • CCS demonstration faces formidable challenges in the absence of targeted support that should include financial support, enabling policies, and an appropriate regulatory framework.
  • Current low oil prices have reduced the incentive for enhanced oil recovery but the fundamental drivers in the PRC remain strong.
  • A phased approach to CCS demonstration and deployment is needed. Early-stage demonstration projects based on low-cost capture in parallel with intensive research and development and limited application in the power sector can bring down costs and deliver new knowledge. Success in the 10 years to 2025 can pave the way for wider deployment of cost competitive CCS from 2030 onward.

There is both strong interest and healthy debate around committing to a CCS Roadmap in the PRC, with several projects showing signs of tangible progress and the NDRC continuing to be actively engaged.


Reducing CO2 emissions from fossil fuel combustion requires pricing the environmental impact of the emissions (carbon pricing), valuing low-emissions technologies, or regulation. Carbon pricing has generally lacked ambition consistent with the global 2°C target, so the prices have fallen far short of levels necessary to drive major technology changes. Regulation to shut down older, more polluting plants has been applied but only in a few countries and then only gently. The driver in deployment of these technologies has been policies to support renewable energy via various forms of subsidy.

In developed economies, government support has existed for CCS technologies, primarily through funding for research and development or for demonstration projects. Yet failure has been more visible than success. European attempts to allocate a substantial block of funds by reserving permits for CCS projects never materialized; the UK process to fund demonstration projects has failed to progress at least twice; U.S. projects, notably FutureGen, suffered several false starts; and the Australia’s CCS Flagship Program failed to make substantial progress on any of its mooted projects. Governments can be criticized for failing to deliver and maintain serious support for CCS and industry for failing to step up with real commitment. And CCS projects do not come cheap.

Growth in energy demand continues in China.

Beyond the Boundary Dam project in Canada, a sole lighthouse on a barren coastline, the hope in developed economies may lie with a couple of U.S. power projects that may still be commissioned soon. So, most governments are no longer actively interested in CCS, if they ever were, and the power generation and coal and gas industries have failed to develop the compelling narrative that would convince a policy maker to risk significant political capital on the alternative.


Current policies and positions by governments and industry will repeat the history of the last decade. For CCS to be deployed at the scale for which proponents have argued and neutral bodies such as the IEA have projected, two things must change. First, governments must adopt credible, long-term climate change policies consistent with the commitments they have made under the Paris Agreement. Second, both governments and industry must themselves be sufficiently convinced of the case for CCS to deliver the major and consistent financial support for early-stage pre-commercial deployment to drive down the cost.

Not many years ago, governments were prepared to see CCS as one of a basket of technologies that would contribute to emissions reduction. On this basis, funding for demonstration projects as described above was established in several developed economies. These projects generally failed to proceed either because the funding was inadequate, the costs blew out beyond the proponents’ expectations, or the proponents themselves abandoned the projects.

Few, if any, political leaders or energy/resources ministers are advocates for CCS today. The political risks are high and CCS proponents have failed to convince politicians with arguments compelling enough to invest scarce political capital. This is despite the logic that suggests if CCS had received the same level of support as wind and solar technologies, the cost of CCS would have fallen as it did for those technologies. And, despite the threat to coal and gas that will follow if governments meet their commitments under the Paris Agreement, those industries have failed to put sufficient financial effort into CCS projects to change the game by demonstrating technical credibility and cost reduction potential.

Credible, stable climate change policies are rare around the world. Even when, as in Europe, emissions trading schemes have been implemented, design flaws or economic conditions have meant that carbon prices have failed to reach levels that would support the widespread adoption of low-emissions technologies. It has fallen to specific subsidy schemes to drive the adoption of renewable energy such as wind and solar power. The possibility that CCS could have delivered similar levels of emissions reduction at similar cost levels remains untested. The result is that politicians shy away from climate change policies that would lead to carbon prices high enough to deploy CCS technologies alongside wind and solar in a lowest cost mix, yet are prepared, often with community endorsement, to subsidize wind and solar power such that the overall cost is almost certainly higher.

The lack of substantial progress with CCS in developed economies leads many to look to the PRC as a possible savior. The PRC government has shown a preparedness to support low-emissions technologies across the spectrum of wind, solar, hydro, and nuclear; and several CCS projects, including enhanced oil recovery and some focused on the coal-chemical sector, are making progress. The current levels of air pollution in their major cities, much associated with fossil fuel combustion, also provide a strong driver to address non-CO2 pollution and greenhouse gas emissions within the same policy response.

The CCS Roadmap described above provides a possible way forward and one that might lead the PRC to a global leadership position on CCS technologies as was achieved with solar. Yet, it is far from clear that the PRC government is any more wedded to this prospect than were western governments over the last decade. Government representatives often share the western view that CCS is just too expensive and means less productivity from the fossil fuels that are burned. Cooperation across governments and with strong support from the coal and gas sector to finance real projects could provide a catalyst.

A compelling case for CCS may yet emerge from a combination of demonstration projects and the emergence of high-cost scenarios for alternative approaches in developed economies. The PRC may support CCS and achieve the major cost reductions envisaged in its Roadmap.


  1. International Energy Agency. (2015, 10 November). World energy outlook 2015. Paris: OECD/IEA.
  2. Asian Development Bank. (2015, November). Roadmap for carbon capture and storage demonstration and deployment in the People’s Republic of China,


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The Role of CCS in a Well-Below 2°C World

By Kamel Ben Naceur
Director, Sustainability, Technology and Outlooks Directorate,
International Energy Agency
Samantha McCulloch
Energy Analyst, International Energy Agency

The ratification of the Paris Agreement marked an historic milestone for the energy sector and confirmed a global target of limiting future temperature increases to “well below 2°C”. Achieving this will require a much faster and more extensive transformation of the energy sector than previously contemplated. All technologies and all options for reducing emissions will need to be embraced—with carbon capture and storage (CCS) being core among these. The Paris Agreement therefore presents enormous opportunities for the deployment of CCS technologies.

CCS provides a unique and important solution to emissions from current and future use of fossil fuels in industry and in power generation. It is the only technology able to significantly reduce emissions from coal- and gas-fired power plants. Crucially, CCS is also one of few technologies that can address emissions from industrial processes, including the production of steel, cement, and chemicals, all of which will remain building blocks of modern society. The Intergovernmental Panel on Climate Change (IPCC) has further emphasized the importance of CCS with bioenergy in delivering future “negative emissions” if more ambitious climate targets are to be achieved.1

The Paris Agreement is an enormous opportunity for CCS.

Fortunately, CCS technologies are now well understood and global experience in delivering large-scale projects continues to grow. The Sleipner CCS project in Norway has now been operating for 20 years, safely and permanently storing almost 17 million tonnes of CO2 deep under the North Sea. The International Energy Agency (IEA) has recently acknowledged this milestone and reviewed the progress achieved in developing and deploying CCS technologies in its report “20 Years of Carbon Capture and Storage – Accelerating Future Deployment”. The report also highlights the importance of CCS in achieving future climate goals.


CCS plays a key role in moving the energy sector onto a pathway consistent with limiting future temperature increases to 2°C. Analysis by the IEA suggests that CCS could account for around 12% of the cumulative emissions reductions needed to transition from a “business as usual” (6DS) approach to a 2°C (2DS) target by 2050 (Figure 1).2 This amounts to 94 gigatonnes (Gt) of carbon dioxide (CO2) captured in the period to 2050, with around 55% of this (52 Gt) in the power sector and 42 Gt in industrial applications and fuel transformation.3 Coal-fired power generation is the single largest source of CO2 captured in the IEA 2°C scenario, with 40 GtCO2 captured in the period to 2050 and around 570 GW of global coal-fired generation equipped with CCS in 2050.

FIGURE 1. CCS is a key contributor in the 2DS.
Source: IEA (2016), Energy Technology Perspectives 2016

Shifting to a well-below 2°C target will likely require even greater deployment of CCS, particularly in industrial applications. In the IEA 2DS, the power sector is virtually decarbonized by 2050, while industry becomes the single largest source of emissions at around 45%, followed by transport (Figure 2). There are alternatives to CCS for further emissions reductions in the industrial sector. The potential for other options, such as energy efficiency and fuel or feedstock switching, to contribute to further emissions reductions is likely to be limited. Faster deployment of CCS in the power sector, including through retrofitting existing coal-fired power plants, could also contribute to achieving a well-below 2°C target.

FIGURE 2. Remaining CO2 emissions in the 2DS in 2050: further reductions in industry needed
Source: IEA (2016), 20 Years of Carbon Capture and Storage: Accelerating Future Deployment

The scale of the challenge associated with limiting future temperature increases to well below 2°C means that achieving “a balance between anthropogenic emissions by sources and removals by sinks” in the second half of the century, as outlined in the Paris Agreement, may not be the end-point for achieving climate goals. Analyses by key institutions, including the Mercator Research Institute,4 highlight that overall emissions will need to be negative in the second half of the century under the more ambitious pathways agreed in Paris. CCS in combination with bioenergy, or BECCS, will be important as one of the few technologies able to deliver “negative emissions”. This was highlighted by the IPCC in its Fifth Assessment Report, where it found that many climate models were unable to achieve concentration goals consistent with a 2°C or well-below 2°C target without significant deployment of BECCS.1


More than any other fuel, coal use will be substantially impacted as the energy sector transitions to a 2°C or well-below 2°C target. The successful and widespread deployment of CCS technologies will be a key determinant of the future role of coal as climate policies are strengthened globally.

In the IEA’s 2DS, around 75% of global coal-fired power generation capacity is equipped with CCS and provides around 3300 TWh of generation in 2050. The remaining unabated plants run at very low capacity factors. In a 2DS, the average emissions intensity of the global power sector must fall from more than 500 g/CO2 per kWh to around 40 g/CO2 per kWh in 2050. In a well-below 2°C case, this may need to be reduced even further.

This leaves virtually no room for unabated coal-fired power plants in the power mix, and even challenges the role for CCS-equipped coal plants in the long term. An ultra-supercritical coal-fired power plant with a CO2 capture rate of 90% would produce emissions of around 100 g/CO2 per kWh— substantially higher than the average global fleet in 2050, notwithstanding a major reduction from the more than 760 g/CO2 per kWh of an unabated plant. Opportunities to further reduce this include technological improvements related to plant efficiency, higher CO2 capture rates, and co-firing coal with biomass in CCS-equipped plants. The latter option, in particular, has the potential to yield zero-emissions coal plants which could be the key to a future role for coal in a well-below 2°C world.

Putting scenario analysis aside, today’s reality is that more than 1950 GW of coal-fired generation capacity currently operates globally, with a further 250 GW under construction and 1000 GW in various stages of planning. Around 500 GW of existing capacity has been added since 2010, and the average plant age for developing countries is around 15 years. Much of this fleet has a technical operating life that extends to 2050 and beyond, meaning that early retirements would be unavoidable to achieve a 2°C target. In practice, this would present significant social, economic, and political challenges, particularly with more than 40% of fossil fuel power generation publicly owned. CCS, including retrofitting, can provide an important and strategic alternative to early retirements, preserving the economic value of these investments while bridging the gap between today’s reality and the achievement of future climate ambitions.


CCS is far from being a new technology. Individual CCS technologies have been used in industry for decades, including the injection of CO2 for enhanced oil recovery purposes, which commenced in the U.S. in the early 1970s. Globally, 15 large-scale CCS projects are currently operating across a range of applications, with six more projects expected within the next 12 months. With all of this experience, it is evident that there are no insurmountable technological barriers to CCS deployment. The part of the equation that has been missing has been the financial incentives and climate policies necessary to support investment.

Over the past 20 years, policy and political support for CCS has fluctuated considerably and provided an uncertain foundation for investment (Figure 3).

FIGURE 3. Fluctuating policy and political support for CCS
Source: IEA (2016), 20 years of Carbon Capture and Storage: Accelerating Future Deployment. Figure adapted from SBC Energy Institute (2016), Low Carbon Energy Technologies Fact Book Update: Carbon Capture and Storage at a Crossroads.

Following the release of the IPCC Special Report on CCS in 2005 and the G8 leaders’ pledge to deploy 20 large-scale CCS projects before 2020, there was a considerable upswing in momentum. New international initiatives such as the Global CCS Institute were launched and around US$30 billion in public funding commitments were made globally, with the aim of supporting as many as 35 projects. However, by 2014 less than US$3 billion of this had been spent, and only seven projects have ultimately received support from these programs.

A number of factors have influenced this, including the failure of the Copenhagen climate negotiations in 2009 which saw climate change temporarily fall down the list of political priorities. Budget pressures following the global financial crisis also impacted public funding availability. Remarkable cost reductions in renewable technologies and advances in energy efficiency have arguably also captured the policy focus.

However, a major contributor was the fact that deploying first-of-a-kind, large-scale CCS projects also proved to be more complex, time consuming, and expensive than many governments and project proponents had anticipated. For every project that has successfully reached a final investment decision, two have been cancelled. This is not necessarily unexpected given the stage of the technology, the need for confidence in storage, and the size of the investment required. Yet it underscores the critical importance of increasing the number of projects under development and pulling through more investment with targeted support and stable policy frameworks.


The analysis by the IEA confirms that the successful implementation of the Paris Agreement will almost certainly require deployment of CCS across industry and power applications, as well as investment in bioenergy with CCS for “negative emissions”. This investment in CCS is not just for the long term, with substantial deployment of CCS needed in the period to 2030 under our lowest-cost scenarios. Enormous opportunities for CCS could therefore emerge as global governments act to implement their Nationally Determined Contributions (NDCs) in parallel with planning for their long-term (2050) climate strategies.A

The importance of accelerating CCS

Yet we must also recognize that the ratification of the Paris Agreement is just the beginning. A considerable gap exists between the level of effort represented in the NDCs pledged prior to Paris, and what is required to achieve the ambitions of the Paris Agreement. IEA analysis finds that the NDCs would put us on a pathway for temperature increases of almost 3°C and would not lead to an emission peak in the near future.5 The difference between this and a well-below 2°C target is immense, and could represent more than 40 years’ worth of current emissions.6

Given the gap between the NDC pathway and a well-below 2°C target, the fact that CCS was mentioned in only 10 out of 162 NDCs could be seen as both a symptom and a cause. CCS is a technology essential for achieving more ambitious temperature targets, but the lower the ambition the less of a role for CCS, particularly in the near term. A refocusing of efforts to deploy CCS will be essential as we work to bridge the gap between action and ambition globally.


More than 20 years of experience with CCS technologies and a growing number of large-scale projects confirms that there are no insurmountable technological barriers to deployment. The ratification of the Paris Agreement now provides the foundation for significantly strengthened climate action that could unlock enormous opportunities for CCS. Given the climate challenge ahead, CCS is a solution that’s simply too big to be ignored, particularly for emissions from industrial processes and today’s large coal-fired power fleet. The coal industry has a particularly strong interest in the widespread deployment of CCS, with the future role of coal in the energy mix inexorably linked to CCS in low-emissions development pathways.


  • A. The decision adopting the Paris Agreement (1/CP.21 paragraph 35) invites Parties to communicate, by 2020, “mid-century, long-term low greenhouse gas emission development strategies”.


  1. Intergovernmental Panel on Climate Change (IPCC). (2014). Climate change 2014: Mitigation of climate change. Summary for policymakers: Contribution of Working Group III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change. Cambridge, U.K./New York: Cambridge University Press.
  2. IEA (International Energy Agency). (2016). Energy technology perspectives 2016. Paris: OECD/IEA.
  3. IEA. (2016). 20 years of carbon capture and storage: Accelerating future deployment. Paris: OECD/IEA.
  4. Mercator Research Institute on Global Commons and Climate Change. (2016). Betting on negative emissions,
  5. IEA. (2015). World energy outlook special report: Energy and climate change. Paris: OECD/IEA
  6. Carbon Brief. (2016). Analysis: Only five years left before 1.5°C budget is blown, (accessed 24 Nov. 2016).


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Beyond HELE: Why CCS Is Imperative Now

By Brad Page
CEO, Global CCS Institute

It is now clear that the outcome of the Paris climate talks was a game changer, delivering a renewed global commitment to addressing climate change. No longer are we aiming to limit global warming to 2°C. We are now aspiring for well below that—perhaps as low as 1.5°C. Significantly, the agreement also sets out global ambition for carbon neutrality by mid-century. In the post-COP21 discussions, thinking has shifted from “how much do we do?” to “how do we do so much? “

But the numbers are confronting.

The targets set by the countries signing up to the Paris Agreement only put the world on a track toward about 3°C. For many countries, the targets they volunteered are more ambitious than they have previously been; for many others, they remain more easily achieved. For some, and especially among developing countries, the outlook is not as simple: Energy poverty must be addressed alongside economic growth and environmental stewardship. Although these are not mutually exclusive, addressing all three imperatives concurrently can be expensive in the immediate term.

But the atmosphere is not forgiving. We are already at 400 ppm of CO2 and on track to exceed 450 ppm. To achieve the Paris ambition, emissions most likely have to peak in the next decade and there is a growing likelihood that negative emissions technologies will be necessary.

Boundary Dam Power Station

Assuming that current and announced climate policies are implemented, the International Energy Agency (IEA) forecasts that, despite the extensive, worldwide government support for renewables and increasing energy efficiency, fossil fuels are expected to meet approximately 75% of primary energy demand in 2040, down marginally from the historic share of around 80%.1

Against this backdrop, energy access in developing countries is the path to improved living standards. The majority of increased fossil fuel usage will come from here, alongside an associated escalation in emissions, unless there are fundamental changes in approach.

Without doubt, visionary, bold, and innovative policy solutions are necessary. It will not be enough to single out popular technologies for support, and hope they will do the job. That is the path the world has been on for at least the past two decades and today we are farther away from our emission objectives, in absolute terms, than we were 20 years ago.

It is clear that renewables and energy efficiency will—must—play a significant and increasing role. Support for these will continue and their penetration will continue to increase from today’s base. But in the time available, this will not be enough.

Industrial processes account for approximately 25% of greenhouse gas emissions.2 Energy efficiency is relevant but the main, perhaps only, technology to address this problem is carbon capture and storage (CCS). Renewables offer very limited potential in this area.

In power generation, the installed stock of fossil fuel plants is so great that much of it will not be retired in the next 30 years. Additionally, Carbon Tracker reports3 that more than 2000 new coal-fired generators are planned for construction by 2030. This level of additional coal-fired generation capacity is completely inconsistent with the Paris Agreement unless it is accompanied by CCS.

To the extent that new coal-fired generators are constructed and operated, it is imperative they are of the highest efficiency available and operated to contribute positively to energy security while minimizing their emissions. HELE (high-efficiency, low-emissions) coal-fired generators need to be the minimum specification acceptable for new-build and replacement coal plants.

Fossil fuel demand growing and reserves robust
Source: IEA World Energy Outlook, 2015 (New policies scenario)
Source: BP Statistical Review of World Energy 2015

But will this be enough against the Paris Agreement backdrop? The short answer is no.

Coal-fired generation technology is mature, relatively low cost, and widely available. Continual research and development over many decades has lifted efficiency from 20% in old subcritical plants to as high as 40+% in the latest ultra-supercritical plants. These improvements in efficiency have also seen greenhouse gas emissions fall per unit of output by upward of 25%.

It is entirely sensible that all new coal-fired generators should be ultra-supercritical. The additional electrical output per unit of fuel as well as valuable efficiencies in water consumption and emissions should make the latest technology (when viewed over the life of the plant) highly attractive. Nonetheless, although this technology represents a huge improvement in all aspects of performance over the average of the global-installed fleet, these plants remain relatively emissions intensive.

Even at 650–800 kg CO2/MWh, ultra-supercritical plants are about twice as emissions intensive per MWh as the latest combined-cycle gas turbines. Yet with the need to peak emissions within 10 years, gas turbines will be unacceptably high in emissions in the short run, unless CCS is part of their utilization.

While this picture leads to a conclusion that CCS is vital, the path to its widespread uptake is far from clear.

Over the decade to 2014, global investment in renewables was just short of US$2 trillion. Over the same period, investment in CCS was US$20 billion.4 How can such a disparity in investment exist if the world is trying to achieve what amounts to a complete energy system redesign—indeed, redevelopment—in the next 35 years?

In short, it comes down to the business case. When there is not a clear and enduring value for carbon dioxide, and policies instead are deliberately constructed to favour specific technologies, then capital will go to where the best reliable return can be achieved. For more than 20 years this has essentially flowed to renewable technologies: first on-shore wind, then solar, and, close on their heels, off-shore wind.

Doubtless this has led to a fast and continuing lowering of the unit price of all of these technologies. When all of the available clean energy technologies are needed to address emissions, this is clearly positive. However, when fossil fuels represent the overwhelming majority of primary energy demand and are projected to do so for another 15–25 years at least, then ignoring the key technology that can make fossil fuels “low emission” directly threatens the ability to arrest the climate challenge. As emissions need to peak in the next 10 years, this looks increasingly unlikely.

Those opposing CCS are vocal but their arguments warrant critical analysis.

Contrary to the views of some, CCS is not experimental. Currently 15 large-scale integrated facilities are operating in various countries around the world, capturing and storing 28 million tonnes of CO2 every year. Another seven are under construction (including two very large power plants) and, when operating in the next 2–3 years, these will increase capture and storage to 40 million tonnes per annum.5

SaskPower carbon capture and storage facility

Others say it is too expensive. “Compared to what?” should be the rejoinder. If the comparison is to unabated fossil fuel technology, then of course it is. In comparison to renewable or nuclear generation options, however, it is rarely more expensive. Successive studies6 have shown that CCS is generally more expensive than old hydro and on-shore wind but generally competitive with utility-scale solar PV, geothermal, and new hydro while being lower in cost than small-scale PV, off-shore wind, nuclear, and the many other nascent technologies—especially when the real cost of filling-in for intermittency is included. Yes, it is a high capital cost addition. But it also delivers dependable, secure, dispatchable baseload, and load-following power. From a system security perspective, few low-emissions alternatives compare favorably.

Another claim is that it simply perpetuates the use of fossil fuels. The alternative, and more realistic, approach is that the continued use of fossil fuels over the period of concern is going to happen anyway. And it will be in large volumes. This is reality. It is simply not possible in the space of one or two decades to switch off fossil fuels. Even if the world’s electricity system could be run exclusively on zero-emissions generation in the time period (highly unlikely, of course), the industrial sector—chemicals, fertilizer, steel, and cement production, for example—will continue to require carbon-based fuels. The industrial processing sector alone is 25% of global emissions and cannot be ignored if climate objectives are to be achieved. Only CCS can deal with these unavoidable emissions. Perhaps more significantly, much of the developing world will exploit its carbon-based fuels, coal key among them, to lift national and personal incomes and give their citizens a better way of life. Plans for new coal-fired power stations confirm this. CCS must be part of the plan for these power stations.

Increasingly it appears inevitable that negative emissions technologies—those that actively take CO2 out of the atmosphere—will be necessary to achieve 2°C, let alone 1.5°C. Few options exist in this area; forestry is obvious, but the time taken to embed carbon in trees is long compared to the rate at which emissions occur. Bio-energy production with CCS is the main alternative and is already a reality; the Illinois Industrial Project at Decatur in the U.S. represents precisely this. But the infrastructure, pipes and storage facilities, doesn’t simply turn up at will. It requires planning, permitting, and proper evaluation and construction, as well as a sound business case and preferably many users to minimize the cost per tonne transported and stored. The likely most efficient approach to this is to start early and decarbonize whole industrial clusters by providing common user infrastructure and rewarding those that choose to move to a low-carbon production model. This is again a question of policy, policy that needs to be long term in its thinking with cost minimizing as a key objective.

After Paris, one thing is clear: There’s no place to hide when it comes to decarbonizing the world. Countries have signed up to an agreement that includes provisions to prevent so-called “backsliding”. Future targets and commitments can only be more ambitious, and if the temperature objectives are to be achieved, then this is necessary and inevitable. Every sector of the global economy will be under close examination, including many (especially in the industrial processing arena) that, to date, have been largely left alone.

Time is short. The challenge is huge.

The overriding guiding principle for decarbonizing should be to do it at minimum cost. That isn’t the track the world has been on for over 20 years as many policies have led to abatement cost multiples above what was necessary.

CCS is consistently reported as having a key role in solving the decarbonization challenge at least cost. Combined with HELE in coal-fired power generation, increased efficiency in many industrial processes, and applied to bioenergy production, CCS can make the difference in whether or not the Paris Agreement objectives can be achieved.

But to do this we need worldwide policies that focus on delivering clean energy, not just those that, for whatever reason, are popular or preferred in any given period.


  1. IEA. (2015). World energy outlook 2015 New Policies Scenario,
  2. IPCC. (2015). IPCC Fifth Assessment synthesis report,
  3. Coalswarm. (2016, July). Global Coal Plant Tracker: Proposed coal plants by country (units),
  4. Bloomberg New Energy Finance. (2014). Carbon capture and storage: Perspectives from the International Energy Agency. Presented at National CCS Week in Australia, September 2014.
  5. GCCSI. (2015). Global CCS Institute status report 2015,
  6. GCCSI. (2015). The costs of CCS and other low-carbon technologies in the United States: 2015 update,


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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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Carbon Capture, Utilization, and Storage

By John Kessels
Executive Editor, Cornerstone

John Kessels, Executive Editor, Cornerstone

In November 2012, Cornerstone was launched as the official journal of the World Coal Association. Cornerstone has since become an internationally recognized credible, independent, high-quality publication, featuring some of the most insightful and informative articles on industry developments. We have looked closely at the technological innovations being pioneered across the coal industry and offered some remarkable thought leadership pieces—from academia, research institutes, investors, and mining companies—that have engendered discussion in the industry.

The mission of Cornerstone was to communicate coal’s involvement in energy communities, the industry’s scientific and technological advancement, and coal’s vital function in propelling the world toward a sustainable future. It also addressed the key challenges that coal faces and brought a wide variety of stakeholders into the discussion to advance the sustainable use of coal. In 2016, Cornerstone has reached more than 70,000 views worldwide and is circulated in print in English and Mandarin. All the articles are accessible at:

After four years, however, it is time to say farewell to Cornerstone. This is our last edition of this journal. In 2017, we will be bringing readers a new journal, named Clean Energy, that will cover not only coal but also other energy technologies, such as solar, wind, unconventional oil and gas, hydrogen energy and fuel cell, energy storage, and smart grid technology developments.

Cornerstone has been instrumental in providing a platform for discussing low-emissions coal technologies, carbon capture and storage (CCS), and the sustainable mining practices being applied across the sector. The journal has also championed the need for policy parity for CCS and for financial investment in low-emissions coal.

So, it is fitting that the final issue focuses on carbon capture, utilization, and storage (CCUS) as we examine the current and future role that CCUS needs to play in the global energy mix. Our cover story, written by the General Manager of the IEA Clean Coal Centre, looks at the urgency of moving CCS from research to commercial development. Other articles examine CCUS developments in Norway and the development of CCUS over the last 20 years. We also explore the challenges and the exciting developments that are happening with CCUS in China.

This issue also examines clean coal technology developments in Japan and the United Arab Emirates. CCUS remains a key technology for the coal and industrial sector. Experts agree that CCUS needs to be better supported politically and economically in order to continue to play an important role in reducing CO2 emissions in the industrial and energy sector.

With this issue, Cornerstone has come full circle. We hope it informs and encourages readers to understand the developments happening with CCUS today.

We would like to extend our gratitude to the Shenhua Group for bringing together stories, knowledge, and insight from various sections of the industry.

On behalf of our team, I hope you enjoy this final issue and we look forward to bringing you the new journal in 2017.


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Volume 4, Issue 3

Volume 4 Issue 3

From the Editor

Coal in Europe

By John Kessels, Cornerstone

Kessels HeadshotThe European Union’s recent ratification of the Paris Agreement and the road ahead to mitigate CO2 emissions will be a challenging task for Europe without recognizing the key role coal plays. Coal is one of the major pillars in power generation for Europe’s 500 million inhabitants. The European Union’s 28 member-states have the third largest energy market in the world. In 2015, coal provided a quarter of the power generated in the EU-28 and remains a secure and affordable energy source.

Cover Story

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

By Hans-Wilhelm Schiffer, World Energy Council

Schiffer ImageThe European Union (EU-28) is one of the largest economies in the world, with a gross domestic product of €14,635 billion in 2015. It has 508 million inhabitants, or 7% of the world´s population. 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.


The Need for Increased Momentum for CCS After COP21

By Andrew Purvis and Ingvild Ombudstvedt, GCCSI

Purvis TOCAs a result of the 21st Conference of the Parties in Paris in 2015, 178 parties to the UN Framework Convention on Climate Change adopted a goal to hold the increase in global temperature to “well below” 2°C, “pursue efforts” to limit the temperature increase to 1.5°C above pre-industrial levels, and further achieve a balance between anthropogenic sinks and sources of greenhouse gases in the second half of the century. To achieve these targets, all emissions-mitigating measures and mechanisms will be needed. Efforts to decarbonize will be needed from both the parties to the agreement and the energy and industrial sectors. This will require increased momentum for energy efficiency and a continuing transition from fossil fuels to renewables. It also highlights the critical role of carbon capture and storage.

Lessons from the “Golden Decade” of Coal for China’s Energy Revolution

By Qian Minggao, China University of Mining and Technology

QianTOCChina is abundant in coal resources, but holds limited oil and natural gas resources. In the past decade, China’s GDP has grown 8–10% annually, and it is the second largest economy in the world. Nearly 70% of its economic growth and primary energy demand has been met by coal. The consumption of coal increased from 1 billion tons in 2000 to nearly 4.2 billion tons in 2014. This four-fold increase within 15 years is known as the coal sector’s “golden decade” (2000–2010).

Enhancing, Preserving, and Protecting North Dakota’s Lignite Industry

By Michael Jones, Lignite Energy Council

JonesTOCNorth Dakota is part of the interior of the United States. Sometimes called the Peace Garden State because it shares a peaceful border with the Canadian province of Saskatchewan, the state is known for its sparse population and its abundant resources—productive farms and energy sources that help feed and power a vast region. However, its most important resource is the perseverance and ingenuity of its 750,000 residents.

Energy Policy

The Eurasian Lignite Backbone

By Jeffrey H. Michel, Independent Energy Consultant

Lignite, a low-grade fossil fuel in geological transition from peat to hard coal, is a mainstay of power generation and heating services between Central Europe and the Mediterranean Sea. Germany is the world’s largest lignite producer with an annual output of 178 million metric tons (Mt) in 2015, covering nearly a quarter of electricity demand. Although mining declined significantly after 1990 in the former East Germany and Czechoslovakia, most other countries have increased usage. Foremost is Turkey, with lignite power generation expected to increase by over 80% within three years.

Turkey’s Attempts to Increase the Utilization of Domestic Coal

By Öztürk Selvitop, Ministry of Energy and Natural Resources

SelvitopTOCTurkey opened its energy industry to the private sector as part of an overall shift toward a market economy in 2001, and, in that context, liberalization and restructuring studies in the energy sector were initiated. Prior to 2001, several models including BOT (Build-Operate-Transfer), BOO (Build-Own-Operate) and TOOR (Transfer of Operating Rights) were implemented to increase private-sector participation in the power sector. Since 2001 under the Electricity Market Law state-owned companies are allowed to finish ongoing construction of power plants and can continue to intervene and build additional new power generation plants if there is a threat to security of supply. As a result of the new law, the private sector has commissioned significant new generation capacity. In particular, new renewables-based generation has been built with support provided by the Renewables Law enacted in 2005.

Present State of and Prospects for Hard Coal in Poland

By Lidia Gawlik and Eugeniusz Mokrzycki, Polish Academy of Sciences

GawlikTOCThe modern economy and the development of civilization are closely related to energy consumption. Fossil fuels (hard coal, lignite, oil, and natural gas) account globally for about 80% of the demand for primary energy sources.1 The dynamics of changes in the structure of the global fuel and energy balance in the past, present, and foreseeable future indicates continuing dependence on fossil fuels as a primary energy source. The share of coal in primary energy supply of the world has increased in recent years, influenced primarily by increased consumption in China, reaching its highest level since 1971: 29% in 2013 and 2014.1 Despite these facts, its role as a fuel of the future is often questioned. This is mainly due to climate change and emissions generated from the use of coal.

Strategic Analysis

Net-Zero Emissions: New Climate Target and New Chance for Coal

By Jon Gibbins and Hannah Chalmers, UK CCS Research Centre

GibbinsTOCAt the Paris climate summit in December 2015, world leaders agreed to work to limit global climate change to 2°C and to try to achieve 1.5°C. To put the necessary cap on total cumulative greenhouse gas (GHG) emissions, leaders also agreed on net-zero emissions; that is, there must be “a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century.”

The Role of Fracking in the U.S. Utility: Battle of Gas vs. Coal

By Jill Tietjen, Technically Speaking, Inc. and Russell Schussler, Georgia Transmission Corporation

TietjenTOCFor decades, coal was the dominant fuel for electric power generation in the U.S. Although advances in natural gas generation technology allowed natural gas to become increasingly competitive with coal and other generation options, regulatory constraints and market influences drove coal to remain the overwhelming source for baseload power throughout most of the 20th century. However, in the early 21st century the advent of horizontal drilling as an adjunct to hydraulic fracturing (fracking) significantly reduced the price as well as the price volatility of natural gas. These changes, combined with increased environmental regulation for coal-fired generation, have led to natural gas surpassing coal in terms of net U.S. generation.

Technology Frontiers

Effect of Coal Beneficiation on the Efficiency of Advanced PCC Power Plants

By Nenad Sarunac, University of North Carolina, Charles Bullinger, Mark Ness, Sandra Broekema, and Ye Yao, Great River Energy

SarunacTOCPulverized coal combustion (PCC) dominates power generation and will continue to do so for the foreseeable future.1 Due to aging of the existing fleet of PCC plants and global increase in electricity demand, especially in emerging economies, a fleet of new highly efficient PCC plants is likely to be deployed.

Improving Flexibility of Hard Coal and Lignite Boilers

By Michalis Agraniotis, Malgorzata Stein Brzozowska, Christian Bergins, Torsten Buddenberg, and Emmanouil Kakaras, Mitsubishi Hitachi Power Systems Europe

AgraniotisTOCThe EU energy strategy for 2020 and 2050 sets specific targets for the transition of the current European energy system and energy market. The aim of the strategy is to encourage a low-carbon energy system with decreased greenhouse gas (GHG) emissions (by 50% compared with 1990 levels until 2050), increased energy efficiency, and a larger share of renewable energy sources (RES). All these developments set new challenges in the conventional thermal power sector. Under these new market conditions, modern, highly efficient natural gas combined-cycle (NGCC) power plants cannot be competitive in several countries and lose market share. Hard coal and lignite power plants are often requested by grid operators to stay in operation as the backbone of the electricity generation system and to increase their operational flexibility, in order to cover the increasing fluctuations of the residual load due to the intermittent RES.

The Łagisza Power Plant: The World’s First Supercritical CFB

By Malgorzata Wiatros-Motyka, IEA Clean Coal Centre

MotykaTOCThe Łagisza power plant in Będzin, Poland, is home to the world’s first 460-MW supercritical circulating fluidized bed boiler (CFB), which remains the largest of its kind outside China. Since beginning commercial operation in June 2009, the plant has attracted considerable interest from all over the world. Experience gained from its design, construction, and operation has been a valuable stepping stone in further developing the technology and implementing it in other countries.

Resource Utilization and Management of Fly Ash

By Jinder Jow, National Institute of Clean-and-Low-Carbon Energy

Chen Globe ThumbnailChina’s primary energy resources are fossil-based fuels: oil, natural gas, and coal, with coal being the least expensive. From a material aspect, coal has both organic and inorganic components, quite different from oil and natural gas which have only organic materials. This article shows the process of a coal-fired power plant and its by-products—from coal mine to electricity or heat. The by-products are (1) NOx, sulfur oxides, Hg, particulate matter (PM), and CO2; (2) wastewater; and (3) fly ash, bottom ash, and flue-gas desulfurized gypsum when an external desulfurization process is used. The solid by-product with the largest volume is fly ash. The fly ash retains the inorganic components of coal after combustion.

Global News

GlobalNewsPhotoCovering global business changes, publications, and meetings

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Global News

International Outlook


Canada’s Saskpower’s C$1.5 billion Boundary Dam Carbon Capture plant at Esteven in Saskatchewan announced in August the plant has captured more than 1 million tonnes of CO2 since its start-up in October 2014. The company is on track to capture annually 800,000 tonnes of CO2 by the end of 2016. Alberta Shell’s Quest carbon capture and storage (CCS) project has also achieved a significant one-year milestone, capturing and storing 1 million tonnes of carbon dioxide (CO2) ahead of schedule.


Shenhua Group and SUEK the Siberian coal energy company, have held a meeting in Moscow to discuss areas of potential collaboration. SUEK is Russia’s largest coal company and Shenhua is the largest coal company in China. Both sides exchanged views on the global coal industry and market dynamics. Shenhua was represented by Vice President Wang Jinli and SUEK by CEO Vladimir Rashevsky with both saying they would find areas in which to cooperate including coal mining, processing, and supply.


The Kemper County energy facility in Mississippi started production of syngas from its second gasifier using locally mined lignite. The project aims to utilize two commercial-scale transport integrated gasification (TRIG™) units to gasify locally mined lignite coal to produce syngas. The syngas will then be cleaned and used to fuel two combined-cycle power generating units each with a net output of 582 MW of electricity.

The WA Parish Carbon Capture Storage (CCS) project, also known as the Petra Nova Carbon Capture Project, is scheduled to be completed by the end of 2016. Globally, the Petra Nova Carbon Capture Project will be the largest post-combustion carbon capture facility on an existing coal plant. The project will use a carbon dioxide (CO2) capture process developed by Mitsubishi Heavy Industries. Approximately 90% of the CO2 will be captured from a 240-MW slipstream of flue gas from the power station’s existing 610-MW coal-fired Unit 8, and extract approximately 1.6 million tons (mt) of CO2 annually. The CO2 will be used for enhanced oil recovery (EOR) at the West Ranch Oil Field.


The Paris Agreement entered into force on 4 November 2016. The threshold for the entry into force of the Paris Agreement was achieved on 5 October 2016. The threshold was reached due to the ratification of the U.S. and China in September and in October the European Union. The key condition of 55 parties to the United Nations Framework on Climate Change Convention, accounting for 55% of total global greenhouse gas emissions, was achieved. In total, 74 countries have deposited their instruments of ratification, acceptance, or approval to the agreement, covering 58.82% of the total global greenhouse gas emissions.

Recent Select Publications

CO2 Building Blocks: Assessing CO2 Utilization Options — U.S. National Coal Council — The assessment was prepared in response to a request from U.S. Secretary of Energy Moniz that the federal advisory council “develop an expanded white paper assessing opportunities to advance commercial markets for carbon dioxide (CO2) from coal-based power generation”. The NCC assessment concludes that CO2-EOR currently represents the most immediate, highest value opportunity to utilize the greatest volumes of anthropogenic CO2, with the greatest near-term potential to incentivize CCUS deployment. The full study is available at

Case Study on Glencore Land Rehabilitation
Initiative in Australia — World Coal Association (WCA) —
The WCA has published a new case study from Glencore which examines the company’s land rehabilitation initiatives in Australia. Glencore’s rehabilitation and restoration plans go beyond the mandatory requirements. The case study reviews the rehabilitation plans taking place at Mangoola, Liddell, Westside, and Mt Owen opencast mines. Each site develops and implements an Annual Rehabilitation Plan. This plan is incorporated into day-to-day operations. Among other aims, the annual rehabilitation planning process seeks to closely integrate rehabilitation with both short- and long-term (life of mine) mine planning and operations, and assist with quality implementation of rehabilitation works as planned and designed. The case study is available at

Key Meetings & Conferences

Globally there are numerous conferences and meetings geared toward the coal and energy industries. The table below highlights a few such events. If you would like your event listed in Cornerstone, please contact the Executive Editor at

Conference Name Dates (2016–2017) Location Website
IEA GHG R&D Programme 13th Greenhouse Gas Control Technologies Conference
14–18 Nov
Lausanne, Switzerland
2016 China International Energy Forum & Exhibition
28–30 Nov
Beijing, China
COAL-GEN 2016 Conference
2–3 Dec
Orlando, Florida, U.S.
17th Coaltrans USA
2–3 Dec
Miami, Florida, U.S.
2017 8th International Conference on Clean Coal Technologies
8–12 May
Cagliari, Italy

There are several Coaltrans conferences globally each year. To learn more, visit


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Resource Utilization and Management of Fly Ash

By Jinder Jow
National Institute of Clean-and-Low-Carbon Energy (NICE),
Beijing, China

China’s primary energy resources are fossil-based fuels: oil, natural gas, and coal, with coal being the least expensive. From a material aspect, coal has both organic and inorganic components, quite different from oil and natural gas which have only organic materials. Figure 1 depicts the process of a coal-fired power plant and its by-products—from coal mine to electricity or heat. The by-products are (1) NOx, sulfur oxides, Hg, particulate matter (PM), and CO2; (2) wastewater; and (3) fly ash, bottom ash, and flue-gas desulfurized gypsum when an external desulfurization process is used. The solid by-product with the largest volume is fly ash. The fly ash retains the inorganic components of coal after combustion.

FIGURE 1. By-products of coal-based energy from coal mine to coal-fired power plant.

Three different coal combustion processes are used to produce energy: pulverized coal (PC), circulating fluidized bed (CFB), and integrated gasification combined-cycle (IGCC). The first two are the most commonly used by coal-fired power plants. The PC process typically has a higher combustion temperature and efficiency than the CFB process, and produces less fly ash with better quality. Fly ash is mostly used in low-end applications, such as buildings and constructions, due to significant property variations that strongly depend on how each coal-fired power plant operates. This article describes the approach taken by the National Institute of Clean-and-Low-Carbon Energy (NICE), a subsidiary of Shenhua Group, to utilize and manage fly ash as a resource to increase its utilization volume and value. The same concept and approach can be applied to the utilization of fly ash or any other by-product related to coal-based energy. Coal-fired power can be cleaner if its by-products can be reduced or utilized.

Up to 60% of fly ash is used in cement and concrete construction in China.


Figure 2 depicts the three fundamental properties of fly ash: particle size distribution and morphology, chemical composition, and mineral composition. As noted, fly ash will differ in these properties, due to the operational differences of various coal-fired power plants. Factors that influence these properties include the coal type/source, pretreatment, combustion process, environmental control system, and the ash collection system.

FIGURE 2. Fundamental properties of fly ash.

Figure 3 shows how these three fundamental properties are linked with the operation of a coal-fired power plant. Several steps need to be taken to utilize fly ash as a resource. Identifying and understanding the properties of the fly ash is the first key step. Obtaining fly ash with consistent properties is the second step. Identifying suitable applications and development of specific products for different uses is the last step to maximize its properties and utilization value.

FIGURE 3. Fundamental properties of fly ash related to coal-fired power plant operation.

Particle size distribution of fly ash depends on the coal’s pretreatment, combustion process, and ash collection system. In general, fly ash has a particle size range of 0.1–600 µm. Fine coal particles produce finer fly ash. Higher combustion efficiency also tends to produce finer fly ash. Fly ash collected at the same plant using different electrostatic precipitators will have a different average particle size and distribution. Finer fly ash usually has a better utilization value due to its higher surface area and reactivity.1 The particle morphology depends on the combustion process. The PC process produces spherical particles due to natural cooling, whereas the CFB process creates irregularly shaped particles due to the fluidizing action.1 The images in Figure 4 show the differences in particle morphologies using a scanning electron microscope. A spherical shape has a better flow property but less aspect ratio effect than an irregular shape.

FIGURE 4. Particle morphology of pulverized (left) and circulating fluidizing bed (right) fly ash.

The chemical composition of fly ash depends on the coal type and the extent and temperature of combustion. The environmental control units used to remove NOx, sulfur, or Hg will also affect the composition. The major chemical compositions are dominated by SiO2 and Al2O3 as an aluminosilicate material followed by four secondary components, CaO, Fe3O4 or Fe2O3, SO3, and unburned carbon (loss on ignition, LOI). Combustion of lignite or subbituminous coal usually produces more fly ash, due to its high ash and CaO content, than does combustion of an anthracite or bituminous coal. The internal desulfurization process where lime is injected into the combustion process can also produce fly ash with high CaO content. Fly ash with more CaO tends to have higher cementitious reactivity. Typically, the PC process produces better fly ash quality with lower LOI, SO3, and CaO contents than the CFB process.

Mineral composition depends on the coal type, coal particle size, and boiler temperature. In general, higher boiler temperatures and smaller coal particles produce fly ash with higher glass content. Fly ash typically has a glass content range of 35–70%. Fly ash with more glass and smaller particle size has a higher pozzolanic reaction. Fly ash with high aluminum content tends to have lower glass content but higher mullite content in its crystalline phase.


Two key issues for fly ash utilization are significant property variation and local supply-demand issues. In China fly ash is used in various applications, such as cement and concrete, walls and building materials, aggregates in road pavement, agricultural use, mine refilling, and mineral extraction.2 The building and construction sectors are major users of fly ash which can meet their low performance requirements. For example, China produced 540 million tons of fly ash in 2014 with a utilization rate of 70%, higher than the global average of 54%.3 The fly ash was used as follows: 60% for cement and concrete, 26% for bricks and walls, 5% for road pavement, 5% for agriculture and mine refilling, and 4% for mineral extraction and other applications. The utilizations are categorized into three types as shown in Figure 5: local massive utilization, high-value utilization, and local ecologic utilization.

FIGURE 5. Utilization types of fly ash.A

Fly ash from coal-fired power plants located near metropolitan areas or large industrial complexes can be utilized to meet local demand in building and construction applications. However, these local applications are typically of low value (low price-to-performance) and only economic within a 100-km distance due to the transportation cost. Coal-fired power plants located in remote areas have limited options for fly ash utilization. Both high-value (high price-to-performance) and local ecologic utilizations become critical to increase its usage. Utilization and management of fly ash must be economically viable in remote locations or regions. In order to increase current utilization value and volume, efforts are underway to identify new applications for high-value and local utilizations. This requires an understanding of materials science and knowledge of possible applications.


To address fly ash utilization and management issues, the first step is to characterize its fundamental properties from individual coal-fired power plants and re-characterize when the operational conditions change. The second step is to obtain fly ash with consistent property qualities through a cost-effective particle control system, particularly for particle size, LOI, and Fe3O4 content. The third step is to select suitable applications based on consistent fundamental properties of fly ash and to develop core technologies and products for full utilization of fly ash to achieve the maximum value. Figure 6 shows how these three steps address both property variation and supply-and-demand issues.

FIGURE 6. Approaches to address fly ash utilization issues.

The fly ash R&D team at NICE has adapted this approach to characterize different types of fly ash and establish a cost-effective particle control system. This particle control system has obtained at least three grades of fly ash with consistent particle size distribution used to develop four products: hydraulic fracturing proppants, fillers, highly active supplemental cementitious (HASC) products, and river sand (RS) products (see Table 1). All products are based on at least one of these three fly ash grades, which are produced from the PC process. The processes of making fly ash-based products do not generate any by-products and consume less energy than the existing products to be replaced.1

TABLE 1. Fly ash-based products developed by NICE.

HASC products can replace up to 50% cementitious materials including cement used in concrete. Concretes using HASC products have higher compressive strengths, including three-day compressive strength which is one of the most important properties of concrete.3 The RS product fully replaces ultrafine sand used in mortar. Fillers can fully replace CaCO3 and other inorganic fillers (2500 mesh or above) used in polymers with better flow property. When the polymers are molten and pushed to flow, spherically shaped fillers help the molten polymer flow better than do irregularly shaped fillers. Fly ash-based proppant properties are either equivalent to or better than three commercially available bauxite-based proppants, identified as SG overseas, YT China, and CQ China, as shown in Table 2.4

TABLE 2. Performance comparison of four different low-density, high-strength proppants.

The three cases described below demonstrate how these products increase the utilization rate and value in local massive and high-value utilizations. The fly ash reference case was obtained from a pulverized coal-fired power plant. The fly ash is rated as Class II according to Chinese National Standard GB1596-2005 for concrete and mortar uses. For the particle size requirements, the GB 1596-2005 standard specifies fly ash with particle size greater than 45 µm and no higher than 25% by weight as Class II fly ash, while ASTM C618 specifies no higher than 34% by weight as Class F. The fly ash cost reference is assumed to be RMB50/ton from a coal-fired power plant and sold to a concrete producer at RMB150/ton, resulting in a gross margin of RMB100/ton.

Case I demonstrates two fly ash-based products used for concrete and mortar as an example of local massive utilization. Case II shows the viability of fillers for high-value utilization along with two products used for concrete and mortar for local massive utilization as a mixed example. Case III maximizes the utilization value and rate by making fillers and proppants using fly ash with an Al2O3 content of at least 35% as the example of high-value utilization only.

Case I: The reference fly ash is classified and converted into a highly active supplemental cementitious (HASC) product to replace 50% cement in concrete, Class II fly ash as an existing product, and a river sand (RS) product to fully replace ultrafine river sand used in mortar at a price of RMB350/ton, RMB150/ton, and RMB50/ton, respectively, under a product split ratio of 20%, 75%, and 5%. The average cost of conversion is RMB80/ton. The calculated gross margin is RMB105/ton. The market size of Class II fly ash used in concrete is assumed to be 71 million tons. The expected fly ash volume processed is 84 million tons to achieve a total extra gross margin of RMB420 million in China. The extra fly ash volume is 21 million tons used for HASC and RS products.

Case II: The same fly ash is classified and converted into fillers, Class II fly ash, and an RS product priced at RMB1000/ton, RMB150/ton, and RMB50/ton, respectively, under a product split ratio of 30%, 60%, and 10%. The average cost of conversion is still RMB80/ton. The calculated gross margin is RMB265/ton. The market size of fillers is assumed to be 1.8 million tons. The total fly ash volume processed is 6 million tons to achieve a total extra gross margin of RMB990 million. The total extra fly ash volume is 2.4 million tons used for filler and RS products.

Case III: Fly ash with high Al2O3 content is classified and converted into fillers and proppants priced at RMB1000/ton and RMB2500/ton under a product split ratio of 30% and 70%, respectively. The average cost of conversion rises to RMB800/ton. The calculated gross margin is RMB1250/ton. The market size of proppants is assumed to be 1.4 million tons in China. The extra fly ash volume is 2 million tons used for both proppants and fillers to achieve a total extra gross margin of RMB2300 million.

All prices stated are a reference for economic comparison and not necessarily the actual prices. Table 3 summarizes the extra fly ash volume and margin created by these three cases. As expected, high-value utilization creates more value and consumes less fly ash volume, while local massive utilization consumes more fly ash volume but creates less value.

TABLE 3. Products to create extra fly ash volume and total gross margin in China.


The development of options to make coal-fired power cleaner by reducing or utilizing more waste by-products is critical to maintain long-term sustainability. Coal has the organic component used to generate heat or electricity while its inorganic component is converted into fly ash through the combustion process. This article discusses options to increase the utilization of fly ash from coal-fired power generation. The fundamental properties of fly ash are particle size distribution and morphology, chemical and mineral composition, and significant variability depending on the operational conditions of individual power plants.

This article demonstrates how to increase fly ash utilization volume and value based on understanding the fundamental properties of fly ash and their property-driven applications for high-value and local building materials uses. Local ecologic utilizations are other options to increase volume and add value to fly ash, including mine refilling, agricultural use, land reclamation, and road construction. These usages are of extremely low value but useful in achieving full utilization, particularly in remote regions. How to achieve positive economic benefits for any ecologic utilization is another important and challenging goal. Resource utilization and management of fly ash requires collaborative efforts among local coal-fired power plants, governments, R&D teams, and enterprises to achieve a full utilization with an overall positive economic benefit in each region.


  • A. High-value utilization includes fillers, flame retardants, low-density foam for fire protection, thermal insulation, and industrial ceramics. Local massive utilization includes building materials for cement, mortar, and concrete, pre-cast, wall materials, and high-density foam. Local ecologic utilization includes mine refilling, aggregates for road pavement, land reclamation, and agricultural use.


  1. Dong, Y., Jow, J., Su, J., & Lai, S. (2013). Fly ash separation technology and its potential applications. Paper presented at the 2013 World of Coal Ash Conference, 22–25 April, Lexington, Kentucky.
  2. National Development and Reform Commission. (2013, 18 February). Fly ash comprehensive utilization management regulation (translated from Chinese).
  3. Jow, J., Dong, Y., Zhao, Y., Ding, S., Li, Q., Wang, X., & Lai, S. (2015). Fly ash-based technologies and value-added products based on materials science. Paper presented at 2015 World of Coal Ash Conference, 5–7 May, Nashville, Tennessee.
  4. Ding, S., Gao, G., & Jow, J. (2016). Resource utilization of high-alumina fly ash: High performance proppant application and development. Paper to be presented at 2016 Asia Coal Ash Conference. Shuozhou, China.


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