Category Archives: Energy Policy

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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Present State of and Prospects for Hard Coal in Poland

By Lidia Gawlik
Mineral and Energy Economy Research Institute,
Polish Academy of Sciences
Eugeniusz Mokrzycki
Mineral and Energy Economy Research Institute,
Polish Academy of Sciences

The 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.

In Europe, the trend is toward closing coal mines and switching to alternative energy sources. Only a few member-states of the European Union (EU) are still producing coal. The EU produced 99.9 million tonnes of coal in 2015, of which 72% (72.2 million tonnes) was from Poland.2 Other EU countries produced small quantities of coal (see Table 1).

TABLE 1. Hard coal production in the European Union in 2014 and 2015, million tonnes.2

A downward trend in production is occurring in most European countries. However, the volume of coal imports to the EU remains high. In 2014, the total imports of hard coal amounted to 204.9 million tonnes, decreasing to 190.6 million tonnes in 2015.


In contrast to other EU countries, the Polish energy and heating sector is reliant on coal. Figure 1 depicts the energy mix in 2015. The hard coal and lignite shares in electricity generation in the energy sector totaled 53.9% and 35.2%, respectively. Meanwhile, wind power accounted for 6.6% of electricity, natural gas provided 2.8%, hydropower 1.5%, and the remainder came from other renewable energy sources.3 Electricity production from hard coal has decreased in recent years from 61.6% in 2007 to 53.9% in 2015. This decrease is a result of increased lignite usage (which is less expensive than hard coal) and the development of wind energy.

FIGURE 1. Poland energy mix in 2015.

In 2014, installed capacity for power generation was 39.4 GW, of which 22.2 GW were hard coal-fired units and 9.2 GW were lignite-fired units. The total capacity installed for units based on solid fuels is 80%. There are additionally 0.9 GW of gas-fired units, 2.2 GW in hydropower plants, and 4.2 GW utilizing other renewable energy sources.4

Bełchatów coal-fired power station.

The modernization of the Polish coal fleet has resulted in improvements in efficiency. SO2 and NOx emissions have also been reduced with the installation of flue gas cleaning. However, older power units still operate at a lower efficiency. There are plans to decommission older plants, with 18 GW of existing coal-fired power station units to be closed by 2050.5 Several existing coal-fired stations have also been replaced with modern, high-performance boilers and turbines with supercritical parameters (i.e., temperature of 600/620°C and pressure of 25–30 MPa). Supercritical lignite-fired power plants are operating at Pątnów (460 MW) and Bełchatów (858 MW), as is a hard coal-fired power plant at Łagisza (460 MW). Poland is also constructing new supercritical plants in Kozienice (1075 MW), Opole (2 × 900 MW), Jaworzno (910 MW), and Turów (lignite-fired, 496 MW).


Coal plays a major role in Poland’s energy security, providing the secure, reliable, and affordable energy supply that is fundamental to Poland’s economic stability and ongoing development. Throughout the economy, coal is used for not only electricity but also heating and industrial activities. It is a key driver for multidimensional government initiatives, among which the most important are those related to: raw materials, infrastructure, and political and international affairs.

The energy policy of a country must ensure a balance between the three elements of sustainable development: energy security, energy affordability, and limiting the impact of energy on the environment.6 There are no simple solutions in the quest to achieve sustainable development. The interests of the private and public sectors, governments and regulators, international pressures, economic, social, and environmental factors, and the behavior of individual consumers are mutually intertwined.

Energy security and independence in meeting energy demand are important elements in creating Poland’s energy policy. Energy imports to Poland contribute only 25.8% of the energy consumed,7 well below the EU average of around 53%.

Poland will continue to use its large coal reserves for the foreseeable future in meeting energy demand and ensuring security of supply. The challenge lies in maintaining low energy costs while meeting sustainable development and environmental protection goals despite the high cost of producing domestic coal per tonne at US$76 compared to US$50–52 for imported coal.8


Poland’s hard coal resources are located in the Upper Silesian Coal Basin and the Lublin Coal Basin. The size of the resource base of hard coal changes annually as a result of exploitation and new exploration. It is also a consequence of changes in the definition of proved reserves due to fluctuating economic and operating conditions.

The documented balance resources of hard coal deposits at the end of 2015 totaled 56 billion tonnes. Steam coal represents 71.6% of the total resources base, that is, over 40 billion tonnes, while the remainder (16 billion tonnes) is coking coal.9

The recoverable reserves are estimated at 1.8 billion tonnes, of which 1.3 billion tonnes are in existing coal mines possessing valid licenses for exploitation. Operating mines may extend and expand the areas with new production licenses. This would result in an additional 5.4 billion tonnes of balance resources, which translates to an additional 1.6 billion tonnes of recoverable reserves in already-developed areas.

The potential lifespan of the currently active mines, determined by dividing the volume of recoverable reserves as of the end of 2015 by the average annual coal production in 2013–2015, varies from a few years to several decades. The potential lifespan of mines depends on the output volume and numerous other factors, including economic conditions, which can result in significant changes. However, it can be stated that the reserves of hard coal in existing coal mines will last for many years.

Documented balance resources in undeveloped deposits (58 deposits) amount to 31.2 billion tonnes.9 The ratio between the balance resources and recoverable reserves is around 0.17, which means 170,000 tonnes of extracted coal per one million tonnes of documented balance resources. Extrapolating this ratio to the total balance resources in undeveloped deposits means a possible 5.3 billion tonnes of coal production. However, it would be expensive to develop them. The major challenge to utilize these coal resources is finding sufficient investment.


The end of the communist era in Poland in 1989 and the introduction of market rules were quite difficult for the country’s entire economy, and especially for the coal mining sector. Previously, the most important function for coal mining was to produce as much coal as possible regardless of costs. Under the new economic criteria and with competition, rules introduced into the Polish economy and coal mining sector made the previous model uneconomic.

However, efforts have been undertaken to restructure coal mines to work more efficiently. One of the most difficult tasks was to reduce the number of miners employed in coal mining. In 1989, 415,900 people employed in the industry produced 177.4 million tonnes of coal, whereas by 2011 the number of people employed had dropped to 114,200 and the output decreased to 75.7 million tonnes. This has resulted in some success, with a profit of more than 3 billion PLN (about US$1 billion) reported by the sector in 2011.

In 2011 steam coal prices began to trend downward. The demand for Polish coal also diminished and contributed to the deterioration of the mining industry. In 2007, the mining industry sold 86.9 million tonnes compared to 73.6 million tonnes in 2015 (i.e., 13.3 million tonnes less). Domestically, 64.6 million tonnes were sold and 9 million tonnes exported. The main customers are in the power industry sector, with 36.6 million tonnes sold, totaling almost half (49.7%) of sales. Other domestic sales include coking plants (10.7 million tonnes), heating plants (4.3 million tonnes), other industrial customers (0.4 million tonnes), and households and small recipients outside industry (12.5 million tonnes).

Due to adverse economic and market conditions, the coal mining sector has been incurring large financial losses since 2012. The consumption of coal in the Polish energy sector is also trending downward. Among the factors impacting the coal sector is the energy and climate policy of the European Union, namely, the European Union Emissions Trading System (EU ETS) and limitations on SOx and NOx emissions as well as the obligatory use of Renewable Energy Sources (RES). Poland is unique among EU countries in its reliance on large domestic resources of coal and the scarcity of other primary energy sources for production of electricity and heat. The country will therefore use coal in the long term.

Coal mining is a significant employer. (Courtesy of Jacek Jarosz, MEERI PAS)

The cost of mining has also increased due to the following factors:

  • Deteriorating operating conditions in most mines
  • Insufficient financial resources for investments to ensure the continuance of mining
  • Failure to adapt the size and quality of production to sales opportunities
  • Trade unions’ salary negotiations
  • No flexible wage model linked to performance
  • Lack of modern solutions for continuous operation, which would contribute to more efficient use of machinery

As a result, the average cost of producing one tonne of coal in 2014 was about 33.46 PLN higher than the average selling price, leading to the collapse of the mining industry.


Coal mining in Poland is expensive due to difficult geological conditions. It costs approximately 285 PLN (US$76) to produce one tonne of coal. The World Bank forecasts that, for the next few years, the price of steam coal internationally will be around US$50–52 per tonne.8 Low coal prices and too much production will challenge the economic viability of Polish mining companies. Therefore, adaptation to the changing conditions is a major task for the mining industry. The key is to maintain competitiveness, especially with the low price of imported coal.

Bogdanka Coal Mine. (Courtesy of Jacek Jarosz, MEERI PAS)

Coal companies are undergoing restructuring. The program aims to reduce extraction costs, increase production efficiency, improve organizational measures, and identify sales opportunities. A key priority is innovation and continuous improvement and to apply more efficient management methods in how miners are employed, such as subcontracting, number of shifts per day, and the type of training and skills required.

Coal will remain a significant contributor to power generation in Poland up to at least 2050. Factors such as its low cost, ongoing investment in new coal-fired power plants, and maintaining existing and new coal mines will ensure its future.10 Even if Polish coal mines reduced production, the new coal-fired power stations would still operate with imported coal.

The power sector’s demand for coal will determine the size of the mining industry in Poland and that will also be influenced by EU climate policy. The government is currently developing a new future energy policy (as yet unfinished and unpublished), based on coal, that will be called “Energy Policy of Poland by 2050”. Hard coal mining currently employs nearly 100,000 miners. The end of the mining industry would be a potential source of social unrest arising from mine closures, unemployment, and lack of alternative employment options. Therefore, the government is expected to adopt policies to assist coal companies.

Coal mining is also a significant source of income for the state and local budgets. The mining enterprises’ obligatory payments required by Polish law have a direct impact on the net profit of mining companies. The payments are elements of the costs of coal production. These are both general taxes (the same as for any other enterprises) and special taxes connected with mining, such as royalties, environmental fees, and other special charges resulting from exploitation deposits, which are very high. One-third of the total revenues from coal sales are allocated in state and local budgets in the form of public payments. It is therefore expected that the government could support mining activity by lowering the level of those payments.

In order to allow the future use of coal in the energy sector and the wider economy, the government aims to accelerate the implementation and further development of clean coal technologies and is currently funding several research initiatives, including:

  • Development of coal gasification technology for highly efficient production of fuels and electricity
  • Production of hydrogen-rich gas in a process of chemical looping combustion of coal
  • Coal gasification processes with CO2 absorption

Currently no cost-effective alternative for coal-based electricity production exists in Poland. The country possesses large domestic reserves of hard coal and lignite, and other energy sources are limited. Gas might become an option in the case of the development of shale gas reserves currently undergoing exploration. Outside of this scenario, expensive imports would limit the expansion of gas power plants. The deployment of nuclear power has been delayed due to various obstacles. A recent study11 shows that building new nuclear power plants is not a cost-effective option before 2040, as it has higher CO2 abatement costs than coal with CCS, wind, or hydro. Development of renewables also encounters greater difficulties in Poland than in other European countries, as the potential for exploiting renewables is lower due to less favorable climatic and geographical conditions. It is therefore planned to continue to use coal and to build high-efficiency coal-fired power stations to reduce CO2 emissions.


Coal companies face many challenges with low coal prices and an oversupply of coal. The closure of unprofitable mines, where capital expenditures are limited, is inevitable. Mining requires more prior preparation to identify production capacity in the future, even for those mines where efficient production is expected.

Investment in the development of new coal mines is being considered despite difficult geological and mining conditions in several mines. There are several projects at different stages of development, indicating that coal remains an integral part of the Polish energy mix. Those projects include:

  • Kopex, a manufacturer of mining machinery and equipment, wants to build a coal mine in Przeciszów. The investment will reach 1.7 billion PLN. The mine’s lifespan is expected to be 30 years.
  • The Coal Holding Sp. z o. o., part of the Australian Balamara Resources Limited group, is planning to invest in some mining projects in Poland, including opening a coking coal mine near Nowa Ruda.
  • The PDCo Sp. z o.o., subsidiary of the Australian company Prairie Downs Metals, wants to build a mine in the Lublin Coal Basin.
  • The Silesian Coal Company (Jan Kulczyk) is planning to build coal mines in Orzesze and Suszec.

The future of coal mining in Poland will strongly depend on adjusting production to meet demand. Improvements in mining production are key, as is closure of unprofitable mines.

Poland’s 20 GW of coal-fired power plants and the additional 2.8 GW under construction will create the future demand for coal. Although diversification of the energy mix is planned, including commissioning nuclear power plants, coal will continue to play the leading role in Poland’s energy mix up to 2050.

A final decision on future energy policy is urgently needed to speed the recovery process of the coal mining industry. Governmental promises to support the process should be confirmed by legal acts, which would create stable conditions for economic restructuring of the sector.


  1. International Energy Agency. (2016). Key world energy trends. Excerpt from World energy balances,—2016-edition—excerpt—key-world-energy-trends.html
  2. EURACOAL. (2016, May). Market report 2016 no. 1,
  3. Polish Grid Company (PSE). (2016). Monthly reports on the functioning of the National Power System and Balancing Market
    [in Polish],
  4. Agencja Rynku Energii (ARE). (2016). Sytuacja w elektroenergetyce (Situation in the power sector) [in Polish]. Warsaw: Agencja Rynku Energii SA.
  5. Gawlik, L., Szurlej, A., & Wyrwa, A. (2015). The impact of the long-term EU target for renewables on the structure of electricity production in Poland. Energy, 92, 172–178.
  6. World Energy Council (WEC). (2015). 2015 Trillema Index: Benchmarking the sustainability of national energy systems. London: WEC,
  7. Eurostat, European Commission. (2015). Energy, transport and environmental indicators. Luxembourg: Eurostat Statistical Books, European Union,
  8. World Bank Group. (2016). Commodity markets outlook, p. 39.
  9. Polish Geological Institute–National Research Institute (PIG-PIB). (2016). Bilans zasobów złóż kopalin w Polsce według stanu na 31. XII. 2015 (Balance of mineral deposits in Poland as of 31 XII 2015 r.) Warszawa [in Polish],
  10. Gawlik, L. (Ed.). (2013). Węgiel dla polskiej energetyki w perspektywie 2050 roku – analizy scenariuszowe (Coal for the Polish energy sector in 2050 perspective – scenario analyses) [in Polish]. Katowice: Górnicza Izba Przemysłowo-Handlowa,
  11. Lehtveer, M., & Hedenus, F. (2015). How much can nuclear power reduce climate mitigation cost? – Critical parameters and sensitivity. Energy Strategy Reviews, 6, 12–19.

The authors can be reached at or


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Turkey’s Attempts to Increase the Utilization of Domestic Coal

By Öztürk SelvitopA
Head of Department,
Ministry of Energy and Natural Resources, Turkey

Turkey 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. Figure 1 shows the different new generation capacity built since 2002.

As shown in Figure 1, during 2002–2015, 41.3 GW of new capacity were commissioned, mostly built by the private sector. Turkey has become increasingly reliant on private-sector power generation investments. In 2002, electricity generation by the private sector made up 40% of Turkey’s total, compared to 79% by the end of 2015.

FIGURE 1. Installed capacity and electricity demand growth (GW).1

The compound annual growth rate (CAGR) of installed capacity during the same period was 6.6%, and was 5.5% for electricity demand. Due to this difference, low wholesale prices, and increased renewable energy capacity in recent years, some domestic coal-fired and natural gas-fired power plants are unable to sell their electricity into the market.

Afsin B coal-fired power plant.

During the 2002–2015 period, 8.6 GW of coal-fired power plants were commissioned with nearly 6 GW of that using imported coal. Coal’s share in the generation mix increased from 24.8% to 29.1%, whereas the share of domestic coal dramatically decreased from 23.7% to 13.8% in the same period (see Figure 2).1 To improve energy supply security, the Ministry of Energy and Natural Resources (MENR) has set a goal to increase the utilization of domestic coal in the energy sector.

FIGURE 2. Coal’s share in Turkey’s electricity generation.1

In 2014 Turkey’s net energy imports were approximately 75% of total primary energy needs. Primary energy production in 2014 was 31 million tonnes of oil equivalent (Mtoe), compared to 24 Mtoe in 2002. Since 2002, there has been a 28% increase with the share of domestic primary energy production decreasing from 31.6% to 25.1%. In contrast, over the same period the share of domestic coal (lignite, domestic hard coal, and asphaltite) in primary energy production increased from 46.9% to 52.7%.2


Figure 3 depicts the increase in lignite production since 1973; however, it is still low compared to the level of reserves in Turkey (see Table 1). Due to the development and utilization of natural gas in the late 1990s, lignite production decreased until 2004; since then private-sector involvement has resulted in an increase.

FIGURE 3. Lignite production in Turkey.2

TABLE 1. Coal reserves* in Turkey (billion tonnes).2
*No official data are available about coal reserves belonging to the private sector.

Since 1973 hard coal production in Turkey has been decreasing (see Figure 4). In 2004, after the allowance of the private sector in hard coal fields by the TTK, hard coal production trended upward, but subsequently began decreasing again and was only 1.4 million tonnes in 2015.2 Hard coal imports, however, have been increasing steadily since 1980 and exceeded 33 million tonnes in 2015, with an increasing number of coal-fired power plants relying on imported coal. Figure 5 indicates the breakdown of hard coal imports by country.3

FIGURE 4. Hard coal production and imports.2

FIGURE 5. Hard coal imports in 2015 by country.3

With regard to the electricity sector, as of June 2016 the total capacity of coal-fired power plants in operation is 16.6 GW, 9.8 GW of which is domestic coal-fired (see Table 2).3

TABLE 2. Coal-fired capacity (GW).1

According to the January 2016 “Progress Report” of the Energy Market Regulatory Authority (EMRA),4 13 coal-fired power plants are under construction with a total capacity of 8.2 GW, of which 2.1 GW will be domestic coal-fired.


Coal, especially domestic coal, has a great importance for MENR and the Turkish government. Although Turkey is not rich in oil and natural gas reserves, MENR believes that import dependency can be decreased by increasing the share of domestic coal and renewables. In several official documents, the government has set targets for increasing the utilization of coal.

For example, Turkey’s High Planning Council (headed by the Prime Minister) endorsed the “Electricity Market and Security of Supply Strategy Paper” in May 2009.5 Electricity generation and capacity targets were set, by sources, to 2023. Regarding coal and hydro, the document calls for all known lignite, hard coal, and hydro resources to be utilized for electricity generation by 2023. For wind and geothermal capacity, the targets were set as 20 GW and 0.6 GW, respectively. Additionally, the document sets target shares of 30% for renewables and for gas and at least 5% for nuclear in electricity generation.

The government’s Tenth Development Plan6 (2014–2018) sets a target of 60 billion kWh of electricity generation from domestic coal by 2018, compared to the 39 billion kWh generated in 2012. Moreover, the plan has 25 Priority Transformation Programs targeting several sectors. One is the Domestic Resource Based Energy Production Program (1.13), which includes the following elements:

    • Developing and implementing a special financing method to utilize coal reserves in large coal basins, such as Afşin-Elbistan and Konya-Karapinar
    • Transferring the major fields to private sector
    • Identifying new coal reserves by accelerating exploration activities
    • Focusing on R&D activities that increase the quality of domestic coals or increase their calorific values
    • Monitoring and, if needed, updating incentive programs regarding investments in domestic coal-fired power plants
    • Rehabilitating lignite-fired thermal power plants owned by the state

MENR’s Strategic Plan (2015–2019) sets similar targets for the utilization of domestic coal.7


Since 2012, the Investment Incentive Program has been active in Turkey. Designed to achieve Turkey’s 2023 vision as well as to advance the production and export-oriented growth strategy, the program supports investments through four different incentive schemes: general, regional, large-scale, and strategic.

Coal exploration, coal production, and domestic coal-fired power plant investments are eligible to apply in the general and regional investment incentive schemes, and are recognized as priority investments. Regardless of the province of the investment, such investments are supported with the 5th Region incentives, under the regional investment incentive scheme.


The Turkish government introduced a new law in June 2016 to encourage the utilization of domestic coal. A new financial model aims to decrease the bureaucratic processes and speed up investments in the energy sector.

The first step in the new model is to establish related companies for each large-scale coal area belonging to EUAS or TKI. The first company established was Çayirhan Energy and Mining Corporation (ÇEMPAS Co.), which is part of EUAS. The Çayirhan region has ~250 million tonnes of lignite reserves suitable for a ~800-MW capacity power plant.

All the necessary expropriation, Environmental Impact Assessment, zoning approval, and other required procedures will be undertaken by ÇEMPAS Co. A power purchase agreement (PPA) has been signed between ÇEMPAS Co. and EUAS for 15 years. ÇEMPAS Co. will then be privatized by a tender by the end of 2016. The bidding will start from US$72/MWh, the bidder with the lowest price in US$/MWh will win the tender. The tender is expected to identify a suitable bidder that will develop the mine, build the coal-fired power station, and operate it.

Grand National Assembly Building in Ankara.

The new legislation also aims to further incentivize use of domestic coal. Turkish Electricity Wholesale and Contracting Co. (TETAS), a state-owned enterprise, has long-term PPA contracts with BOT, BOO, and TOOR types of power plants. Moreover, TETAS purchases all the electricity produced by EUAS and sells it to distribution companies, which in turn sell it to end users. If TETAS needs additional electricity to meet its obligations, it can purchase electricity from domestic coal-fired power plants by tender. The Council of Ministers (CoM) decided that TETAS may purchase up to 6 billion kWh of electricity by tender in 2016 and 18 billion kWh of electricity in 2017 with the price of 185 TL/MWh (~US$60/MWh). Under this decision, TETAS announced a tender in August, and has started purchasing electricity from domestic coal-fired power plants.

The share of coal-fired power plants using imported coal has been increasing steadily compared to those using domestic coal. This can be attributed to several reasons, such as lower cost and higher calorific value. In August 2016 the CoM decided to slow down imported coal-fired power plant investments by setting a purchase limit of US$70 per ton of imported coal used for power generation. If an investor purchases imported coal less than a price of US$70/ton, they must l pay the difference to the Ministry of Economy as a tax. However, if they purchase the coal for over US$70/ton then no tax is applicable.


The Turkish government aims to increase the share of domestic coal in the electricity mix. According to MENR’s unofficial target, the envisaged electricity generation mix will be 30% renewables, 30% coal (half will be domestic coal), 30% natural gas, and 10% nuclear. Although the government has taken several significant steps, it will not be easy to achieve its targets, especially for coal, due to both national and international developments.

For example, the State Council requested an overall Environmental Impact Assessment for imported coal-fired power plants located in the eastern Mediterranean region of Turkey. The rationale was that these plants are located in close proximity and the government wanted to better understand the possible environmental effects and impacts of the power plants to the region.

In addition, after COP21 and the resulting Paris Agreement, business as usual for fossil fuel-based power plants, including those in Turkey, is unlikely. Turkey signed the Paris Agreement in April 2016. According to its Intended Nationally Determined Contribution (INDC),8 70.2% of the total emissions expressed in CO2 equivalent (CO2e) are generated by the energy sector. The INDC is aiming for a 21% reduction in greenhouse gas (GHG) emissions from a business-as-usual scenario by 2030 (from 1.175 million tonnes to 929 million tonnes of CO2e). Achieving that target will require 10 GW solar and 16 GW wind capacity, utilizing all hydro potential (around 36 GW), and commissioning a nuclear power plant (4.8 GW) by 2030. The separate goal of increasing the share of domestic coal will make the INDC target even more difficult to achieve and will require renewable investments to be implemented without delay.

Since 2013 the OECD export credit committees have been reviewing export credit rules for coal-fired power plants. As a result, a program was introduced in November 2015 with new rules for official support of coal-fired power plants, including restrictions on official export credits for the least efficient coal-fired power plants.9

There are many challenges to coal-fired power plant investment in Turkey. The government’s current policy seeks to provide a stable investment environment to increase domestic coal production and utilization, thus securing the country’s supply of energy. In the medium term, the share of coal is expected to reach 30%, which is currently around 20% in terms of installed capacity. In this way, the system will be reinforced and baseload needs will be fulfilled, providing the delivery of both sufficient and good-quality electricity to consumers.


  • A. All the comments and the opinions in this article are the author’s and do not reflect the official opinion of the Republic of Turkey Ministry of Energy and Natural Resources.


  1. Turkish Electricity Transmission Corporation (TEIAS). (2015). Electricity generation & transmission statistics of Turkey,
  2. Ministry of Energy and Natural Resources, Directorate General for Energy Affairs, Republic of Turkey. (2015). Energy balance sheets,
  3. Turkish Coal Enterprise (TKI). (2015). Coal (lignite) sector report [in Turkish], p. 33.
  4. Energy Market Regulatory Authority (EMRA). (2016). Progress report of licensed electricity generation projects [in Turkish],
  5. High Planning Council Decision. (2009). Electricity market and security of supply strategy paper,ı%2fElectricity%20Market%20and%20Security%20of%20Supply%20Strategy%20Paper.pdf
  6. Ministry of Development, Republic of Turkey. (2014). The Tenth Development Plan 2014–2018,
  7. Ministry of Energy and Natural Resources, Republic of Turkey. (2015, 17 February). Strategic plan 2015–2019,
  8. UN Framework Convention on Climate Change. (2016). Republic of Turkey Intended Nationally Determined Contribution,
  9. Organisation for Economic Co-operation and Development (OECD). (2015, 18 November). Statement from participants to the Arrangement on Officially Supported Export Credits,

The author can be reached at


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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.


Lignite deposits between Germany and southeastern Europe1 constitute 45% of the EU’s domestic energy reserves.2 Mined lignite exhibits an energy content (heating value) considerably below that of wood pellets (17 MJ/kg) due to high water permeation and non-combustible ash and sulfur. The shallow deposits nevertheless permit surface extraction at a lower final energy cost than imported gas and coal.

At highly efficient power stations connected by conveyer belt to adjacent mines, Germany has achieved fuel expenses below 15 € per MWh of electricity.3 Even when transported to distant plants by rail,4 lignite provides lower and more predictable pricing than natural gas.

Lignite grid power costs vary significantly in the EU and Turkey due to differences in mining operations and thermal quality. The particularly low energy content of local deposits in Greece (3.8–9.6 MJ/kg at EURACOAL country profiles) makes lignite-fired electricity generation the most expensive at 59.9 €/MWh.5 Romania achieves 54.2 €/MWh, followed by 53.6 in Germany, 52.7 in Turkey, 40.3 in Serbia, 39.0 in the Czech Republic, 38.6 in Poland, and 31.6 in Bulgaria.


Before 1990, East Germany (the German Democratic Republic) was the world’s largest lignite producer with over 300 Mt per year (18 t per capita) mined in Lusatia (near the Polish border) and in Central Germany. About 50 Mt/a of low-moisture briquettes were pressed from crude lignite for domestic and industrial heating.

Natural gas has since replaced briquette firing. Four central power stations as well as municipal CHP plants and sugar producers remain, together with the 900-MW Schkopau industrial plant that supplies grid electricity, 16-2/3 Hz railway power, and process heat for organic chemical manufacturing.

Eastern German mining output has dropped to a quarter of former levels, while annual production in the western German Rhineland has fallen less—from around 120 Mt to 95 Mt—due to plant retirements and efficiency measures.6

A new lignite power station.


A comparison of mining figures from the 1970s with current statistics shows that lignite dependency has declined in only three economies: Germany, the former Czechoslovakia (now the Czech Republic and Slovakia), and Hungary (see Figure 1). Lignite usage in Slovakia has fallen to 2.2 Mt/a, or less than 0.5 t/a per capita.

FIGURE 1. Annual lignite production 1979 and 2014.

Lignite mining has otherwise increased significantly. In 2014, the countries that previously comprised Yugoslavia produced a combined 51.1 Mt, compared with 31.7 Mt at the end of the 1970s. Both Greece (48 Mt) and Poland (63.9 Mt) doubled annual tonnage, while lignite usage in Turkey more than quadrupled to 61.5 Mt in the same period.

Lignite reliance is increased by auxiliary energy services (see Figure 2). For instance, total primary energy consumption in the Czech and German economies approaches six metric tons of coal equivalent per inhabitant. However, lignite is responsible for over 30% of overall energy demand in the Czech Republic due to greater heating utilization.

FIGURE 2. Ratio of lignite to total energy demand.

As indicated in the ranking diagram of Figure 3, district heating7 invariably incurs a higher level of dedicated fuel usage. In the case of Poland, heating demand is only partially covered by lignite due to the threefold reliance on hard coal that satisfies 43% vs. 12.9% of total energy requirements.

FIGURE 3. Ranking of district heating to lignite usage.


Burning a ton of mined lignite emits about a ton of CO2. At below 900 Mt/a, global lignite combustion equates to less than 3% of accountable CO2 emissions that totaled 35.7 Gt in 2015. Lignite provides particular logistical and geological benefits compared with other energy sources. Locating large power plants adjacent to mines precludes transport energy losses. Combined heat and power generation increases net fuel utilization. Unlike gas and hard coal, lignite deposits release only negligible methane effluents. Biomass combustion, on the other hand, contributes significantly to climate change with CO2 emissions that persist in the atmosphere.

Following nuclear phase-out legislation enacted in 2011, Germany has been deviating from its 2020 greenhouse gas reduction target of 40% referred to 1990 (see Figure 4). Emissions of 908 Mt in 2015 would need to be reduced by another 159 Mt to meet this obligation, roughly equivalent to all lignite emissions in the electricity sector.

FIGURE 4. Greenhouse gas emissions and targets in Germany.

The Central German lignite miner MIBRAG (Mitteldeutsche Braunkohlengesellschaft mbH) estimates that switching to gas generation under the EU Emissions Trading Scheme (ETS) would entail a 10-fold price increase, resulting in a doubling of electricity rates.8 In contrast with imported fuels, domestic lignite enables calculated costs to be maintained while providing the revenue streams required for post-mining landscape reclamation.


There are several countries in the eastern Mediterranean region that consume over four tons of lignite per capita annually (see Figure 5). The lower heating value of southern European lignite requires greater quantities of lignite to be burned.

FIGURE 5. Lignite production per capita, 2014.

The Czech Republic, however, uses the most lignite energy per inhabitant. Tonnage is comparable to that of Balkan countries, but heating values are in the range of 10.9–18.2 MJ/kg under current contracts. Prehistoric volcanic activity has resulted in both high carbon density and the imbued sulfur formerly responsible for forest mortality Waldsterben) in the absence of SO2 emission filters. Central German deposits north of the intervening Ore Mountains exhibit similar geological characteristics.


Lignite with thermal grades between 7.8 and 11.3 MJ/kg is used in Germany to generate nearly a quarter of the country’s electricity (155 TWh/a in 2015). Together with heating services, lignite covers 12% of overall energy demand. Renewable power provides the same amount of primary energy. However, it is dedicated chiefly to supplanting Germany’s remaining eight nuclear reactors that are being phased out by 2022 in compliance with the 2013 federal coalition agreement.

Nuclear generation accounts for 7% of primary energy and 14% of grid electricity. Renewable power exceeding 30% (196 TWh) must attain a commensurately higher post-nuclear level before lignite generation could be appreciably diminished. Due to ongoing delays in transmission line construction from offshore wind farms, that objective is unlikely to be achieved for another decade.

Licensed lignite reserves in the lower Rhine valley (currently 95 Mt/a) were recently reduced by 400 Mt in the RWE Garzweiler II mine, but without revising the final 2045 production date. A proposed power plant in Central Germany, a flexible 660-MW two-turbine design, was canceled by MIBRAG in April 2014. The corporation’s Czech owner, Energetický a Prumyslový Holding (EPH), together with PPF Investments has instead bought all four Vattenfall lignite mines and three power stations in Lusatia plus one Central German 934-MW block at Lippendorf. The combined capacity of approximately 8.1 GW includes the 2575-MW Boxberg site with a variable-fired 310–675-MW generator dedicated in 2012.

Two nearby Lusatian 500-MW units (of six blocks total) at Jänschwalde are being relegated to reserve status in 2018–2019 under a federal subsidy agreement. The MIBRAG 392-MW Buschhaus plant in Lower Saxony and five older RWE blocks in the Rhineland are also included in the staged retirement program, comprising 2.7 GW of overall capacity, which is intended to avoid 12.5 Mt CO2 annually.9

The recent reorganization of RWE and EPH will enable the German lignite industry to maintain high grid dependability standards as nuclear power is superseded by renewable energies.


Domestic lignite and hard coal currently meet 56% of energy demand in Poland and account for nearly 90% of electrical power generation. Although particular coal operations are being terminated, lignite deposits extending below the Neisse River from Germany will enable new plant capacities to be added. A 100-km2 surface mining site is undergoing preliminary licensing at Gubin-Brody to produce 17 Mt of lignite annually over 49 years from seams 140 m deep. PGE Polska Grupa Energetyczna intends to erect three 830-MW generation blocks for operation beginning in 2030.10

In southwest Poland at Turów, PGE began construction of a 450-MW lignite plant11 in May 2015 to complement the existing six 250-MW turbines at this location. The close proximity of Germany and the Czech Republic could promote the international development of reduced-emissions lignite technologies.

Europe’s largest lignite power station at Bełchatów with 5354-MW generation capacity has been modernized for extended operation. All major lignite sites are prepared for CCS retrofits if warranted by EU decarbonization strategies, with CO2 storage proposed under the Baltic Sea.


Since the 1990s, the Czech semi-state energy corporation ČEZ has upgraded its power plant fleet, beginning with the desulfurization of 6462 MW of installed lignite capacity.12 The Tušimice II (4 ×200 MW) and Prunéřov II (5 × 210 MW) power stations have been completely refurbished for generation until at least 2040. Restrictions imposed in 1991 by Parliamentary Resolution 444 for Northern Bohemian lignite mining have been successively lifted.

Mining operations are being prolonged from 2036 to 2049 at Bílina to supply an additional 100 Mt of lignite to the newly constructed Ledvice 660-MW plant. The single-generator design expands the existing 330 MW of electrical capacity, providing heat to 300 commercial customers and 20,000 private households.

During 2014–2015, over 1 Mt/a of Central German lignite was shipped by rail from MIBRAG mines to the Opatovice and Most-Komořany power plants, which are likewise owned by EPH. While these imports have since been discontinued, briquettes manufactured by MIBRAG with low-sulfur RWE lignite continue to be delivered to the Czech domestic heating market.

Ongoing lignite dependency is sustained by district heating services. Nuclear generation capacities may be expanded in future decades at Dukovany and Temelin.


Over 95% of Bulgarian lignite is mined in the Maritsa East (Iztok) Basin. The 240-square-mile expanse is the largest mining site in southeastern Europe, making its operator, Mini Maritsa-Iztok EAD, the most important employer in Bulgaria. The local lignite exhibits a 16–45% proportion of ash with heating values ranging from 6.5 MJ/kg for steam grades to 7.3 MJ/kg for briquette manufacturing.13 The 1.95–2.4% sulfur content is higher than in northern European deposits.

In addition to two successively modernized power stations with 2365 MW, the AES Bulgaria 600-MW Galabovo plant completed in 2011 constitutes about 5% of the country’s installed power capacity. The € 1.3 billion installation uses approximately a quarter (5 Mt/a) of the lignite mined at this location.


Romanian lignite with 7.2–8.2 MJ/kg has a comparatively low moisture content of 41–43%. Lignite accounts for nearly one-fourth of primary energy consumption and about half of electricity generation,14 with demand at around 30 Mt/a. However, oil, gas, and coal contribute to broad domestic supply diversity. Romania also has the highest installed wind power capacity in southeastern Europe with over 3.1 GW.


The Visonta and Bükkábrány surface mines operated by Mátrai Erőmű ZRT northeast of Budapest provide about 90% of Hungarian lignite. The overburden-to-lignite ratio of 9:1 indicates high expenditures for earth-moving. Lignite is used to supplement the country’s natural gas resources. The Mátra Visonta power station comprises five lignite-fired boilers with 876-MW total generation along with two gas turbines of 2 × 30 MW. Biomass is also co-fired up to 10%. Lignite in combination with non-fossil generation therefore serves to cushion the power market against price volatility.


Lignite significantly contributes to domestic energy security in Greece and the former Yugoslav states (see Figure 6). Mining has been terminated in Croatia, but the remaining Balkan countries are using their lignite resources. The thermal qualities available in Slovenia (11.3 MJ/kg) and Serbia (7.8–8.2 MJ/kg) are comparable with northern European grades. Lignite provides half of Serbia’s total primary energy (see Figure 7).

FIGURE 6. Greek and Balkan lignite production 2014.

FIGURE 7. Ratio of Balkan lignite to total energy demand.

New power plants in the region are dependent on external financing, such as the 660-MW Ptolemaida V expansion in Greece co-funded by the KfW German Development Bank. Although the underlying decisions have been criticized by environmental organizations such as the WWF,15 economic stabilization takes priority over climate policies. Plant expansions await approval at Kolubaru (2 × 375 MW) in Serbia and near Přistina (2 × 300 MW) in Kosovo, where Europe’s fourth-largest lignite resources (after Poland, Germany, and Serbia) are located.16 Future generation may be developed with greater reliance on renewable energies.


In 2015, Turkey met 12% of overall electricity demand with lignite plant capacity of 8.1 GW.17 According to research by the Institute for Energy Economics and Financial Analysis, the most recent energy legislation will raise lignite power generation from 31.2 TWh in 2015 to 57 TWh by 2018. Newly constructed plants would receive guaranteed revenues of 8 cents per kWh, necessitating a 3.5 cent subsidy at current power trading prices.

Tentative Chinese financing of US$ 10–12 billion was announced in 2014 to expand the existing 2795-MW AfSin-Elbistan generation site to 8 GW.18 Overall, more than 80 coal and lignite plants have been variously listed in planning and construction.

Despite the carbon footprint inherent to increased fossil fuel usage, Turkey’s Intended Nationally Determined Contribution (INDC) statement, submitted on 30 September 2015 for climate negotiations in Paris, has established that greenhouse gas emissions could be reduced by up to 21% below business as usual (BAU) in 2030 by including land use, land use change, and forestry (LULUCF).19 Comprehensive mitigation plans are intended to abate up to 255 MtCO2eq by that time over BAU.


Lignite remains a reliably calculable domestic energy resource in most countries between Germany and Turkey. Heating services in combination with power generation provide highest fuel utilization. The retirement of aging power plants additionally contributes to fulfilling CO2 reduction obligations.

The increasing deployment of renewable power technologies challenges the competitive advantage of conventional fuels in electricity generation. Established district heating networks, however, depend widely on low-cost lignite extracted as needed from surface mines. There are no comparable biomass resources in Europe.

Significantly, Turkey is expanding lignite utilization despite having twice the solar irradiation of Germany, where 16% of worldwide photovoltaic capacity is currently installed. Since renewable energy deployment entails particularly high technology outlays, adequate infrastructure prerequisites have yet to be established in the Mediterranean region.


  1. EURACOAL. (2014, 4 December). COAL: Fuel for the 21st century. Coal in Europe 2013 [map],
  2. EURACOAL. (2014). Coal: Fuel for the 21st century,
  3. Michel, J. (2015, 27 October). German accord: It will take a lot more to beat lignite. Energy Post,
  4. Michel, J. (2015). Lignite rides the rails in Europe. Cornerstone, 3(3), 41–44,
  5. Krommydas, T. (2016, 9 February). Lignite in the Greek energy system: Facts and challenges,
  6. Statistik der Kohlenwirtschaft. (2015, February). Braunkohl-enförderung [in German],
  7. Euroheat. (2015). Statistics overview: Country by country,
  8. Mitteldeutsche Braunkohlengesellschaft. (2016, 8 January). Jahresabschluss zum Geschäftsjahr vom 01.01.2014 bis zum 31.12.2014 [in German],
  9. EnerData. (2016, 30 May). European Commission clears closure of German lignite-fired power plants,
  10. Schroeter, S. (2015, 9 December). Polen plant neues Braunkohle-Großprojekt an deutscher Grenze [in German],
  11. Mitsubishi Hitachi Power Systems. (2014, 17 July). MHPS signs contract on project to construct lignite-fired ultra-supercritical-pressure thermal power unit in Poland,
  12. CEZ Group. (n.d.). Fossil power plants,
  13. Mini Maritsa-Iztok. (2016). Coal,
  14. CEE Bankwatch Network. (2014, July). Briefing paper: Turceni coal power plant rehabilitation (p. 9),
  15. WWF. (2015, February). Clean alternatives to Ptolemaida V,
  16. EURACOAL. (2013). Coal industry across Europe,
  17. Dilek, P.Y., & Schlissel, D. (2016, June). Turkey at a crossroads (p. 7). Institute for Energy Economics and Financial Analysis. Cleveland, U.S.
  18. Coskun, O. (2014, 5 May). Turkey, China in talks on $10-12 billion energy investment: Minister. Reuters,
  19. Climate Action Tracker Partners. (2015, 22 October). Turkey,

The author can be reached at


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Policy Parity for CCS Would Move the U.S. Closer to Its Climate Goals

By Janet Gellici
Chief Executive Officer, National Coal Council

The most impactful action the U.S. can employ to reduce CO2 emissions is to incentivize the rapid deployment of carbon capture and storage (CCS)A technologies. Unfortunately, to date U.S. federal and state policies have severely tilted the energy playing field. Existing incentives for CCS are simply too small to bridge the gap between the cost and the risk of promising, but immature, CCS technologies vis-à-vis other low-emissions technology options. While the U.S. Department of Energy has stewarded a successful research and development program to spur early development of CCS technologies, insufficient overall support has hindered commercial deployment.

Other low-emissions technologies have benefited from substantial government support. The success of policy and financial incentives afforded to the renewable energy industry in the U.S. provides ample evidence that government support can be the critical enabler for bringing scale and speed to clean energy technology deployment.

The National Coal Council white paper on low-emissions policy parity offered several recommendations to advance CCS technology development and deployment.


The National Coal Council (NCC) is a federally chartered advisory group to the U.S. Secretary of Energy, providing advice and recommendations on general policy matters relating to coal and the coal industry. In November 2015, the members of the NCC completed a white paper for the secretary that detailed incentives and policies that could be employed to level the playing field for deploying CCS technologies in the U.S. This article highlights key findings and recommendations from the report, “Leveling the Playing Field: Policy Parity for Carbon Capture and Storage Technologies”.1


The guiding principle in advancing a level playing field for various low-emissions energy resources is to ensure that U.S. citizens and businesses have access to reliable, low-cost electricity that can meet various regulatory drivers. Parity connotes a concept of fairness and an assurance that the same set of rules apply to all players. A metaphorical playing field is said to be level if no external interferences affect the ability of the players to compete fairly. Policies and incentives that grease the skids for one resource and/or erect hurdles for others impede our nation’s economic and environmental objectives while imposing undue economic hardship on our citizens.

Policy parity is important to meeting the diverse set of U.S. energy policy objectives. Those objectives have consistently focused on providing a reliable, secure, and low-cost supply of energy, and in recent years have increasingly directed energy production and consumption toward environmental goals. CCS is essential to meeting each of these objectives.

Policy parity for low-emissions electricity sources could enable growth of CCS, similar to what has been observed for wind power in the U.S.

CCS technologies provide the most impactful opportunity to capture, use, and store a significant volume of CO2 from stationary point sources. Such technologies can be used to reduce CO2 emissions from electric generation as well as from key industrial sectors, including cement production, iron and steel making, oil refining, and chemicals manufacturing. CCS technologies help maintain electric reliability in a carbon-constrained world by supporting baseload generation that enables the grid to maintain voltage, frequency, and other attributes essential to reliable power supply.

Additionally, CCS technologies significantly reduce the costs of decarbonization.2 Not including CCS as a key mitigation technology is projected to increase the overall costs of meeting CO2 emissions goals by 70% to 138%.3,4 Finally, the commercial deployment of CCS preserves the economic value of fossil fuel reserves (coal and natural gas) and associated infrastructure.

Other energy technologies have benefited greatly from substantial government support (see Figure 1). In 1992 when Congress enacted the Section 45 renewable energy tax credit, the U.S. had less than 2000 megawatts (MW) of installed wind-generating capacity.5 Today, there are 69,471 MW of installed wind capacity.6 Wind energy prices have dropped from more than $50/MWh in the late 1990s to less than half that cost in 2014.7 The industry credits government policy for its success: “With a two-thirds reduction in the cost of wind energy over the last six years, the renewable production tax credit (PTC) is on track to achieving its goal of a vibrant, self-sustaining wind industry.”8

FIGURE 1. Public policy drives investment.
Source: Carbon Capture and Storage: Perspective from the IEA Ellina Levina, Sydney, Australia, 2 September 2014

Policy and financial incentives have brought scale and speed to renewable energy deployment and helped reduce the cost of these technologies. In contrast, policies that disadvantage fossil fuels have had a suppressing effect on deploying CCS technologies. Policy initiatives must provide positive economic signals for deployment of CCS technologies, recognizing that these technologies are still immature and not yet commercially available in the power sector.

Commercializing CCS requires a level playing field and a correction to the existing “dis-parity” that exists between CCS and renewables.


In March 2015, the U.S. Energy Information Administration (EIA) produced a report valuing subsidies and incentives provided to various forms of energy.9 The report shows that the single largest recipient of federal energy subsidies is, by far, renewables, which, in 2013, received more than 12 times the subsidies received for coal—$13.227 billion for renewables versus just $1.085 billion for coal. It also revealed that renewables received 72% of total subsidies while coal received just 6%. As shown in Table 1, U.S. government support to launch CCS is not remotely comparable to that given to renewables.

TABLE 1. Incentives for renewable electricity generation compared with electricity generation with CCS
Note: DOE issued a solicitation for up to $8 billion in loan guarantees for advanced fossil energy projects on 12 December 2013. To date, no loan guarantees have been made for an advanced fossil energy project. It is unclear whether any applications have been submitted.

The Congressional Research Service (CRS) also released a report in March 2015 assessing the value of energy tax credits for various fuel resources.10 CRS noted that, in 2013, the value of federal tax-related support for the energy sector was estimated to be $23.3 billion, of which $13.4 billion (57.4%) supported renewable energy and $4.8 billion (20.4%) supported fossil fuels.

Financial support outside typical funding mechanisms for energy has also favored renewables over other fuel sources. Funds for renewable projects under the American Recovery and Reinvestment Act (ARRA) were $20 billion versus $3.4 billion for coal.2

In addition to financial support, renewables have benefited significantly from regulatory mandates creating a guaranteed market for wind, solar, biomass, and other alternatives to fossil and nuclear power. These renewable energy standards obligate utilities to obtain a specified percentage of their electricity from renewable energy sources.


Leveling the playing field for CCS will require a combination of financial incentives, regulatory improvements, and research, development, and demonstration catalysts, as well as international collaboration. It will also require that U.S. and global policymakers demonstrate a firm understanding that fossil fuels will be used in the coming decades to a greater extent than today, resulting in an urgent need for CCS deployment.

Financial Incentives

Financial incentives for CCS must be substantially increased and broadened to include incentives available to other low-emissions energy sources. Up-front incentives that reduce risk to capital should be emphasized and designed with a recognition—as with wind and solar in the 1990s—that CCS is an immature technology with up-front risks and high initial capital costs. Operating incentives are important to ensure a steady long-term revenue stream and lessen direct costs to consumers.

Perhaps the single-most important mechanism to spur CCS deployment may be the use of a “contracts for differences” (CFD) structure. This approach would provide for a limited number of projects to bid to the federal government for financial support using a combination of proposed incentives, including:

  • Limited guaranteed purchase agreements
  • Market set asides (similar to state renewable energy requirements)
  • Clean energy credits
  • Production tax credits
  • CO2 price stabilization support for CO2 storage
  • Electricity price stabilization support
  • CO2 injection credit
  • Tax-preferred and tax-exempt bonds
  • Master limited partnerships
  • Loan guarantees

All energy sources are required for the lowest-cost approach to widespread emissions reductions.

Regulatory Improvements

NCC recommends DOE take the lead, working with sister agencies, in developing a regulatory blueprint to remove barriers to the construction and development of projects with CCS, including industrial and power generation plants, transportation options, and injection sites. The regulatory barriers that could be addressed include:

  • Injection Barriers—The EPA’s 111(b) and 111(d) regulations impose reporting rules discouraging, as opposed to encouraging, CO2 utilization.
  • New Source Review—Requirements discourage retrofits of CO2 and other carbon reduction technologies to existing plants.
  • Infrastructure Siting—Granting authority, similar to provisions under the Natural Gas Act, for federal eminent domain for siting and construction of CO2 pipelines.
  • Storage Siting—DOE should identify and certify at least one reservoir capable of storing a minimum of 100 million tons of CO2 at a cost of less than $10/ton in each of the seven regions covered by the agency’s Regional Carbon Sequestration Partnership program.

Research, Development, and Demonstration

NCC recommends DOE substantially increase its budget for RD&D funding for CCS. In concurrence with the CURC-EPRI Roadmap,11 NCC recommends fully funding 80% federal cost share for early-stage RD&D, 100% federal cost share for large-scale pilots, and 50% cost share for commercial demonstration projects.

Communication and Collaboration

NCC encourages DOE to propose an international pool of funds specifically set up for the implementation of 5–10 GW of globally based CCS demonstration projects at scale.

Finally, NCC recommends that DOE be a tireless advocate in all venues for recognition that fossil fuels will be used in coming decades to a greater extent than today to fuel a more populous, developed, urban world. Acknowledgment of the continued global reliance on fossil fuels will enhance the likelihood of support for efforts to achieve meaningful CO2 emissions reductions.


The U.S. increases its chance of success in meeting its global CO2 emission reduction goals when it commits with urgency to the deployment of CCS technologies. Such a commitment begins with the establishment of policies and incentives to level the playing field for CCS.


  • A. The term “CCS” as used in this article denotes both carbon capture and storage (CCS) and carbon capture utilization and storage (CCUS).
  • B. Budgets for “Renewables” reflect funds budgeted to the Office of Energy Efficiency and Renewable Energy for the line items “Solar Energy”, “Wind Energy”, “Water Energy”, and “Geothermal Technologies”. Budgets for “CCS” reflect funds budgeted to the Office of Fossil Energy for the line items “Carbon Capture” and “Carbon Storage”. As noted in the chart, no funds were budgeted for CCS demonstration projects (i.e., CCPI). The budget for CCS does not reflect funding for technologies not under the CCS budget that have application beyond electric generation, such as oxy-combustion and chemical looping. Budgets available at
  • C. While approximately $30 million of this credit has been claimed, no evidence could be found of the credits being claimed by power projects with CCS.


  1. National Coal Council. (2015, November). Leveling the playing field: Policy parity for carbon capture and storage technologies,
  2. National Coal Council. (2015, February). Fossil forward: Bringing scale and speed to CCS development,
  3. Intergovernmental Panel on Climate Change Working Group III (2014). Climate change 2014: Mitigation of climate change, Fig. TS-13, p. 60, (2014),
  4. International Energy Agency. (2012). Energy Technology Perspectives 2012: Pathways to a clean energy system,
  5. Rugh, L. (n.d.) American wind industry: Past and future growth. American Wind Energy Association,
  6. American Wind Energy Association. (2015, 22 October). U.S. wind industry third quarter 2015 market report – Executive summary,
  7. Lawrence Berkeley National Laboratory. (2015, August). 2014 wind technologies market report highlights. U.S. Department of Energy,
  8. American Wind Energy Association. (2015, 10 September). AWEA white paper: Renewable production tax credit has driven progress and cost reductions, but the success story is not yet complete,
  9. U.S. Energy Information Administration. (2015, 22 March). Direct federal financial interventions and subsidies in energy in fiscal year 2013,
  10. Sherlock, M., & Stupak, J. (2015, 19 March). Energy tax incentives: Measuring value across different types of energy resources. Congressional Research Service, R41953,
  11. Coal Utilization Research Council and Electric Power Research Institute. (2015, July). The CURC-EPRI Advanced Coal Technology Roadmap: July 2015 update,


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Juggling Development Objectives and the Role for Coal After the Paris Agreement

By Milagros Miranda R.
Policy Director, World Coal Association

As of 2015 the world has a new global framework for sustainable development, supported by these four pillars: the Paris Agreement on climate change, the UN 2030 Agenda for Sustainable Development, the Sustainable Development Goals (SDGs), and the Addis Ababa Action Agenda on Finance for Development (AAAA). There are crucial and supportive links between these as the new framework calls for a holistic and integrated approach to guide actions toward achieving sustainable development.

Adopted in December 2015, the historic Paris Agreement has 178 signatures. To enter into force, however, the agreement requires ratification by 55% of countries that represent at least 55% of the global emissions reductions. Currently, only 19 countries, representing 0.18% of global emissions, have ratified the agreement.1 Notably, a second UN assessment report on the Individual Nationally Determined Contributions (INDCs) filed by each country indicates that implementation of the current INDCs would not fall within the scope of the 2°C scenario by 2025 and 2030.2 In reality, the global emissions levels as a result of these INDCs are expected to be higher compared with global emissions levels in 1990, 2000, and 2010.

The growing population in the developing world will require increased energy over the next several decades.

The Paris Agreement’s aim is to set a low-emissions path by which the world should hold the increase in the global average temperature to well below 2°C above pre-industrial levels and pursue efforts to limit the temperature increase to 1.5°C above such levels. This goal is further stressed in Decision 1/CP.21, which adopts the Paris Agreement and emphasizes the urgent need to address the significant gap between the aggregate effects of parties’ mitigation pledges in terms of global annual emissions of greenhouse gases by 2020 and aggregate emission pathways consistent with the agreement’s goal.1

Achieving both a low-emissions path and the goals in the Paris Agreement will require countries reliant on coal to implement high-efficiency low-emissions (HELE) and carbon capture and storage (CCS) technologies.

The success of the agreement relies on the implementation of the INDCs that develop into NDCs once a country ratifies the agreement. To achieve a successful, real, and effective Paris Agreement, implementation must be ambitious and efficient. The international community should focus primarily on support and assistance to coal-reliant countries with limited resources in implementation of HELE technologies. The provision of adequate technological and economical resources will allow those countries to achieve and scale up their mitigation ambitions.

The Paris Agreement and Decision 1/CP.21 request parties with INDCs containing a time frame up to 2025 or 2030 to submit new NDCs by 2020, and to periodically increase their ambitions. In 2018, parties will meet to assess all efforts undertaken to peak global greenhouse gas emissions. These events will mark important stepping stones toward increasing the ambitions of the NDCs.

The INDCs submitted by many countries are conditional, stating that if adequate technological and financial support is not forthcoming they will be unable to fulfil their current pledges or offer more ambitious pledges in the future.

Climate finance, technology transfer, and capacity building were potential deal-breakers to adoption of the Paris Agreement. Failure to address technological and financial support issues is likely to result in the unsuccessful implementation of the Paris Agreement. Those same issues also present difficulties for achieving the SDGs and the UN Agenda for Sustainable Development.


Energy is an essential enabler of development. However, 1.1 billion people globally lack access to electricity.3 This reality is one of the greatest challenges of our time.

Climate change and energy access are embedded in SDG 13 (take urgent action to combat climate change and its impacts) and SDG 7 (ensure access to affordable, reliable, sustainable, and modern energy for all), respectively. As countries work toward those goals, they are simultaneously working to address other development needs and priorities—some of which are embedded in other SDGs and some in their INDCs concerning mitigation and adaptation objectives.

Coal continues to play a critical role in the world economy. Globally, coal accounts for around 29% of primary energy supply and 41% of electricity generation.4 It is an essential raw material in the production of 70% of the world’s steel and 90% of the world’s cement, and its use will remain critical in supporting infrastructure, modernization, and urbanization efforts in the world, especially in emerging economies.4

Climate change and energy are not competing priorities. Rather, climate and energy action are complementary and can be mutually reinforcing. With HELE technologies, countries can use coal more efficiently to reduce emissions while increasing energy efficiency in the electricity generation sector. Utilization of HELE technologies will enable countries to improve energy access without undermining their climate objectives. In that way, policies supporting access and deployment of modern and cleaner coal technologies will actually address climate and energy objectives.

Developing countries are forecast to increase their coal use to meet electrification needs. According to the International Energy Agency (IEA), even with a significant increase in use of renewables, coal will still be a substantial source of energy in 2040, accounting for 30% of global electricity generation. Despite reducing its share of electricity generation from 41% to 30%, coal will increase in terms of total electricity generated, reaching almost 24% growth in absolute terms by 2040.4

Growth in coal power generation is driven almost exclusively by Asian economies. According to the IEA, coal is the fuel of choice in Southeast Asia, where energy demand will increase from current levels by 80% by 2040.5

“One size fits all” does not apply when dealing with mitigation objectives. Availability, reliability, affordability, and energy security are the key factors that influence countries’ energy mix. Depending on national priorities and circumstances, countries will apply different policies and technologies to achieve their energy and development objectives.

Coal-using countries will continue to use it because it is affordable, reliable, and available. This is particularly true with developing and emerging economies. A major challenge for those countries is developing policies compatible both with a sustainable development path and their INDC mitigation objectives.

The IEA forecasts that, by 2040, India’s energy consumption will be more than OECD Europe combined. India, as China did before it, will fuel its economic growth with coal, because it is affordable and available. India’s INDC highlights that coal will continue to dominate power generation in the future. Its government is implementing several initiatives to improve the efficiency of its coal power plants, and future policies will focus on developing and deploying cleaner coal technologies such as supercritical and ultra-supercritical.6 As India’s INDC states, “Given the current stage of dependence of many economies on coal, such an effort is an urgent necessity.”7

In China, India, and other developing countries, coal contributes substantially to the baseload electricity that is critical to economic growth and energy access. Moreover, coal-fired power plants can support renewables deployment, making it more viable and counteracting its intermittent nature.8

Hence, moving away from coal is not a realistic solution to the climate challenge faced by developing countries which must juggle other priorities simultaneously: energy access, growing electrification rates, energy security, poverty alleviation, and other environmental objectives. Implementation of HELE and CCS technologies, however, can offer realistic options to developing countries. According to the IEA’s Coal Industry Advisory Board, “Coal-fuelled power plants are indispensable in the near future and thus more focus should be put on making coal technology more efficient and clean. It is a false notion, at least for the next 50 years, that coal-fuelled power plants can be completely replaced with non-conventional technology.”8


HELE coal technologies increase the efficiency of coal-fired power plants and substantially reduce CO2, NOx, SO2, and particulate matter (PM) emissions. A one-percentage-point improvement in the efficiency of a conventional plant results in a 2–3% reduction in CO2 emissions. With supercritical and ultra-supercritical HELE technologies, power plants can achieve efficiencies of up to 42% and 45% (LHV), respectively.9

China offers an example of how countries can change the way they use coal. Measures implemented in China include the adoption of high-efficiency advanced boiler technology and emissions standards for coal-fired power stations. Using supercritical HELE technologies, Unit 4 at the Zhoushan power station achieved thermal efficiency levels equal to or even better than levels achieved in some ultra-supercritical units. Similarly, the Ninghai power station utilizes supercritical and ultra-supercritical HELE technologies—and releases almost five times less SOx, NOx, and PM than the average coal-fired power station in China. Table 1 shows the saving rates of both plants concerning CO2, SO2, NOx, and PM emissions.

TABLE 1. Annual emission reductions of SO2, NOx, PM, and CO2 in Zhoushan Unit 4 and Ninghai Units 5 & 6 power station in China8

Nineteen developing countries have recognized the importance of HELE technologies as mitigation tools by committing to their use in reducing emissions from coal-based energy generation in their INDCs.10 Collectively these countries are responsible for 44% of the world’s emissions and include Bangladesh, China, India, Egypt, Japan, the Philippines, and Vietnam, among others.

According to an article published in the Proceedings of the U.S. National Academy of Sciences, increase in energy demand might be driving a “renaissance of coal” in developing countries, “which is not restricted to a few particular cases but instead is a general phenomenon occurring in a broad set of countries”.11

China and India are the two largest fast-growing developing countries that have increased use of coal to meet energy and electricity demand, and have also begun to switch from subcritical to supercritical and ultra-supercritical HELE technologies. Other coal-producing and -consuming countries in the developing world following suit include South Africa, Indonesia, Kazakhstan, Thailand, Colombia, and Malaysia. It will be particularly important that the rest of Asia follows at a rapid pace.12

Bangladesh, for example, has 121,160 MWe of coal-fired power generation capacity planned or under construction post-2015, of which 5440 MWe is planned to be ultra-supercritical.12 In its INDC, Bangladesh has pledged that 100% of new coal-based power plants will use supercritical technologies by 2030. For this to happen, Bangladesh has estimated that an investment of US$16.5 billion is required.13

Clearly, the transition pace from older, less efficient, and higher emission subcritical technology to more advanced HELE technology must be accelerated. However, without the needed support, the INDC pledges will not be implemented and countries will continue to allocate economic resources to subcritical capacity, thus missing a vital opportunity to slow emissions growth. Figure 1 depicts the projected CO2 emissions reductions achievable by switching from subcritical to ultra-supercritical technologies, in India, China, and other Asian countries.

FIGURE 1. IEA-CCC study on potential HELE impacts in Asia12

World Coal Association studies indicate it will cost US$31 billion to convert 400 GW of coal capacity from subcritical to HELE technologies in non-OECD countries by 2040, saving around six billion tonnes of CO2 from 2015 to 2040.14

HELE coal technologies are also critical precursors to CCS. Without CCS, achieving the goals in the Paris Agreement will be more expensive.15 According to the IEA, “CCS is a critical component in a portfolio of low-carbon energy technologies aimed at combatting climate change. Fossil fuels will continue to dominate primary energy consumption for the foreseeable future increasing the urgency of CCS deployment.”16 The Boundary Dam coal-fired power station in Canada demonstrates that CCS can achieve 90% CO2 emissions reduction.1

Over the last 20 years, CCS has been applied to many uses and with multiple processes and fuels. Industrial applications of CCS are equally important within a low-emissions path.

The IEA forecasts that, by 2050, emissions from coal-fired electricity generation need to be reduced by around 90% if the world is to achieve a 2°C scenario.17 This is doable only with implementation of HELE and CCS. All sources of energy and a varied portfolio of low-emission technologies will need to be implemented with countries’ forthcoming NDCs to achieve electricity for all.


Governments and policymakers in countries reliant on coal and with ambitious INDC pledges will need to use and promote HELE and CCS technologies. Without their use, any transition toward a sustainable and low-emissions energy system will be difficult. International financial and technical institutions also play a critical and catalytic role in accelerating that transition. Without technical and finance support, decision makers will be reluctant to invest in the best available technologies, due to upfront capital investment costs. As indicated by the Addis Ababa Action Agenda on Finance for Development, public-private partnerships must ensure that HELE and CCS are part of national investment plans and decisions, to avoid unnecessary delays in achieving mitigation objectives.

The Paris Agreement established a Technology Framework to provide overarching guidance to the Technology Mechanism of the Convention in facilitating technology development and transfer. One key area of work will be the provision of enhanced financial and technical support for the implementation of the Technology Needs Assessment and Technology Action Plans.

As many developing countries have included HELE coal technologies in their INDCs, those technologies will be part of their Technology Action Plans and most likely require the new Technology Framework to facilitate the required technology transfer and financial support.

UN financial and technological institutions such as the Green Climate Fund and Climate Technology Centre and Network are technology-neutral. These institutions should provide the necessary support for the development of HELE and CCS technologies when countries request it.

A different approach will neglect the reality of the global electricity generation system and result in the likely failure of implementing and achieving the Paris Agreement’s goals. As Yvo de Boer, former Executive Secretary of the UN Framework Convention on Climate Change, has warned: “Without support for new highly efficient coal plants, the world may end up with something much worse.”18


    1. United Nations Framework Convention on Climate Change (UNFCCC). (2016). Paris agreement—Status of ratification,
    2. UNFCCC. (2016, May). Updated synthesis report on the aggregate effect of INDCs,
    3. Sustainable Energy for All. (2016). Ending energy poverty,
    4. International Energy Agency (IEA). (2015). World energy outlook 2015,
    5. IEA. (2015). World energy outlook special report. Southeast Asia energy outlook special report,
    6. Minchener, A. (2015). High efficiency low emissions coal power plants: Challenges and opportunities worldwide,
    7. UNFCCC. (2016). India’s Intended Nationally Determined Contribution: Working towards climate justice,
    8. IEA Coal Industry Advisory Board. (n.d.). The socio-economic impacts of advanced technology coal-fuelled power stations,
    9. World Coal Association (WCA). (n.d.). High efficiency low emissions coal,
    10. WCA. (n.d.). Low emissions coal technologies pledges,
    11. Steckel, J.C., Edenhofer, O., & Jakob, M. (2015). Drivers for the renaissance of coal. Proceedings of the National Academy of Sciences,
    12. Minchener, A. (2015), High efficiency low emissions coal power plants: Challenges and opportunities worldwide. Presentation,
    13. UNFCCC. (2015). Intended Nationally Determined Contributions: Ministry of Environment and Forests: Government of the People’s Republic of Bangladesh,
    14. WCA. (n.d.) High efficiency low emissions coal,
    15. Intergovernmental Panel on Climate Change, Working Group III. (2014). Climate change 2014: Mitigation of climate change,
    16. IEA. (2013). Technology roadmap: Carbon capture and storage,
    17. IEA Technology Roadmap. (2013). High efficiency low emissions coal fired power generation,
    18. Shankleman, J. (2015, October). Former UN climate chief: Why efficient new coal plants should qualify for climate finance. BusinessGreen,


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The Importance of System Utilization and Dispatchable Low-Emissions Electricity for Deep Decarbonization

By Jared Moore
President, Meridian Energy Policy

At COP21, all participating countries formally agreed to create self-imposed plans to limit global warming to 1.5˚C. Achieving this goal will effectively require complete decarbonization of the electricity sector. The conclusions in this article demonstrate that it is important to recognize this long-term goal—deep decarbonization—when crafting climate policy.

Moore Opening Image

The lowest-cost approach to deep decarbonization will likely rely on large-scale dispatchable low-emissions energy, such as nuclear and fossil-fueled power plants with CCS.

Deep decarbonization necessitates nearly all electricity generation come from low-carbon (i.e., low-emissions) power plants, which tend to have higher capital costs and lower marginal (fuel) costs. The exclusive use of capital-intensive power plants increases the importance of system utilization (i.e., using all the electricity a power plant is capable of producing). To assess how differing electricity mixes affect utilization under deep decarbonization, I created a dispatch model to quantify system-level electricity costs. The analysis was based on different scenarios using unique contributions of wind, solar, and dispatchable low-carbon (DLC) generation. DLC is defined as any low-emissions power plant that is not intermittent and is capable of producing power every hour of the year. This includes nuclear power and natural gas and coal-fired power plants with carbon capture and storage (CCS). Though nuclear and CCS plants have unique costs and load-following capabilities, I assumed they were identical for modeling purposes. Based on data from the U.S. state of Texas, this analysis demonstrates that DLC, solar, and storage are very likely required for cost-effective deep decarbonization because these technologies offer the highest system utilization.


The lack of coincidence between the supply of some renewables (wind and solar) and electricity demand underpins the challenge of heavily relying on such power plants under deep decarbonization. Matching supply and demand using wind and solar is challenging because the supply is driven by variable weather cycles. These diurnal (i.e., daily) and seasonal cycles are a result of the earth’s rotation and its tilted axis, respectively. Electricity demand also follows diurnal and seasonal cycles, but peak supply and demand do not match. On a diurnal cycle, solar energy supply peaks during the middle of the day, but power demand tends to peak hours later during the hottest part of the day. On a seasonal cycle, solar energy supply peaks at the summer solstice but the hottest weather of the year (peak air conditioning load) does not occur until months later.

Wind energy supply also has diurnal and seasonal cycles, but the relationships are more complex and unpredictable. Wind is driven by a myriad of local mechanisms, but in many regions, including our study area of Texas, the prevailing factor is the difference in heat (pressure) between the equator and the poles. As a result, wind’s predominant cyclical characteristic is a seasonal anti-correlation with temperature (demand). This study is limited to Texas, specifically ERCOT (Electric Reliability Council of Texas), which serves the vast majority of the Texan load.

While the supply pattern of wind in Texas is not applicable for every region of the world, we can assume that the overall model results and policy implications are relevant to most regions. Solar patterns are similarly diurnal everywhere, of course, and wind has been observed to be seasonally anti-correlated with load in China,1 India,2 and Australia.3

The dissimilar supply and demand patterns have profound implications for system utilization under deep decarbonization. For example, the variation in seasonal load in the ERCOT region is affected by 25% solar penetrationA and then an additional 35% wind penetration (see Figure 1).B

Moore Figure 1

FIGURE 1. Average monthly net load in Texas (ERCOT) after 25% solar, 35% wind penetration

Since solar energy is positively correlated with load on a seasonal basis, adding solar reduces the seasonal variation that must be served by non-renewable generators. Adding wind to solar, however, has the opposite effect because wind’s negative seasonal correlation with demand combines with the slightly early seasonal peak of solar generation. Inevitably, given these seasonal relationships, any combination of wind and solar energy dominating the energy mix will result in oversupply in the spring and undersupply in the late summer. This implies that if DLC generators, such as natural gas and coal with CCS, are required to meet late summer load, they will suffer from low utilization in the spring because of the oversupply of renewable energy. While some argue that DLC generation is too expensive under full utilization, its costs will only increase if it is limited to seasonal utilization. So policymakers face a dilemma: if they lean heavily on intermittent renewables to meet modest decarbonization goals, they increase the risk of oversupplying energy diurnally and/or seasonally and vastly increasing the total system-level costs of electricity.


Demand shifting and energy storage are two frequently mentioned technologies that could help resolve the challenges with intermittent renewables. However, battery storage is technically limited. For example, batteries can transmit only a limited amount of power (MW) and they can only transmit that power for a limited duration—thus limiting the amount of energy (MWh) that can be stored. These constraints are particularly relevant to storing renewable energy since the oversupply episodes can be both acute and chronic.

To demonstrate how power and energy constraints can limit the effectiveness of battery storage, the net load (difference in hourly supply and demand) of three example days in March, May, and August were modeled (see Figure 2). Negative net load indicates oversupply and positive net load indicates undersupply. Two deep decarbonization scenarios were examined. The “80% Wind Solar” case represents the net load where 80% of annual load is met exclusively with wind and solar energy, and the “80% DLC Solar” case represents a scenario with 60% DLC and 20% solar (i.e., 80% low-emissions energy). In both cases the remainder is met with unabated natural gas plants.

Moore Figure 2

FIGURE 2. Net load in ERCOT region under 80% decarbonization scenarios

The oversupply and undersupply episodes in Figure 2 are more severe in both magnitude (MW) and duration (MWh) in the “80% Wind Solar” case. The March oversupply episode is persistent and does not allow an energy arbitrage (i.e., storing and selling) opportunity. Utilizing the March supply episode will require storage over long time periods, resulting in infrequent battery utilization. Seasonal storage is very unlikely to be economically competitive given the quantity of batteries required and the limited arbitrage opportunities per year. Diurnal storage (i.e., energy arbitrage on a daily basis) would require less battery capacity and would permit batteries to be used hundreds of times per year.


To achieve deep decarbonization, some oversupply is inevitable regardless of the mix of renewables and DLC employed. Therefore, deep decarbonization will likely increase the opportunities for energy arbitrage. Additionally, storage and demand response can offer other services such as capacity, ancillary services, and transmission. It is likely, therefore, that some energy arbitrage potential will be available at little cost.

However, while it is likely that more storage will be available in the future, the amount will be limited as the value of storage suffers from diminishing returns.4 Fundamentally, energy arbitrage opportunities decrease as more storage is added to the system, making storage decreasingly valuable.4 There are also decreasing returns on the other services offered by storage, too. For example, only a very small amount of storage is required to saturate the ancillary services market.5 Furthermore, demand response can shift load only for a very limited duration (~8 hours), and this severely limits its ability to rectify persistent oversupply episodes.

There are too many unknowns to determine how much storage is economically justifiable in the long term. As a point of reference, a 2015 study examined various storage technologies and costs under deep decarbonization and found that battery storage capacity of no more than ~25% of the peak demand was economically justified, even if storage costs halved from current rates and the capital costs of DLC generation were $9000/kW.6 The U.S. Energy Information Administration estimates the capital cost of coal with CCS and nuclear at $4700/kW and $5500/kW, respectively.7

Given the likelihood that a limited but appreciable amount of storage will be available, I assumed that, for all deep decarbonization scenarios, one Tesla Powerwall was installed free of cost in every home in the study area of ERCOT. The purpose of this exercise was to determine whether the addition of storage inspires a fundamental pivot toward different decarbonization strategies. This amount of storage equates to 60 GWh and 17.5 GW of capacity (25% of peak demand). Though this is a significant amount of storage, 60 GWh of storage could only absorb about 8% of the 18 March renewable oversupply episode in Figure 2. Additionally, while the oversupply was as high as 60 GW, the batteries could not absorb anything greater than 17.5 GW.


To quantify the mix of wind, solar, and DLC generation required for each scenario, I constructed an hourly dispatch model that linearly scales hourly supply data to meet hourly demand for electricity. Transmission and thermal constraints were neglected, as this analysis is intended to isolate system utilization, not grid flexibility.

Eight energy mix scenarios were modeled (see Figure 3). The base case is a reference scenario where it was assumed that all MWh are served by unabated natural gas.C Two modest decarbonization scenarios were modeled: an exclusive renewable case (Figure 1) and a DLC-dominated case with DLC and solar generation developed at a 3:1 ratio (60% DLC/S). The 80% and 90% DLC/solar scenarios further develop DLC and solar generation at the same 3:1 ratio to fulfill more aggressive low-carbon energy requirements. Additionally, we show a new scenario, named “90% Diverse”, with the initial buildout of renewables from Figure 1 (25% solar, 35% wind) and then DLC filling the remainder low-emissions energy required.

Moore Figure 3

FIGURE 3. Energy scenarios examined for modest and deep decarbonization for one year in ERCOT

The results shown in Figure 3 demonstrate that increasingly aggressive decarbonization will result in oversupply. This is especially true in the absence of DLC generation as the total MWh generated are higher in those cases.

To show the value of storage for scenarios in Figure 3, their marginal utilization rates were quantified with storage and without storage (see Figure 4). The dotted lines represent the marginal rate of low-emissions electricity utilization with one Tesla Powerwall (60 GWh of storage for the region) added per home.

All systems suffer from low utilization under deep decarbonization, especially without storage. In addition, the model results demonstrate that storage can be more productive in a system dominated by DLC and a small amount of solar energy (green lines in Figure 4). DLC and solar pair so well with storage because of the diurnal nature of the oversupply episodes: Solar energy tends to oversupply during the day while DLC generation tends to oversupply at night. As their oversupply episodes are less dramatic and occur diurnally and at different times, the battery can perform energy arbitrage more frequently, increasing its value.

Moore Figure 4

FIGURE 4. Marginal utilization rate of low-emissions energy under deep decarbonization

Having shown that deep decarbonization can lead to low utilization under certain high-renewable scenarios, it is important to then estimate how the cost of low utilization can affect overall system-level costs and also the marginal cost of carbon mitigation ($/t CO2). Under full utilization it is assumed that wind, solar, and DLC power plants would have an unsubsidized levelized cost of energy (LCOE) of $80, $90, and $100/MWh, respectively. Theses assumed costs were informed by the estimates from the EIA,7 but ultimately were picked arbitrarily to demonstrate the importance of system utilization over LCOE.

In addition, the reliability aspect of system-level costs is taken into account by assuming a value of capacity at $330/MW-day.8 It was assumed that the equivalent load-carrying capability of wind and solar start out at 25% and 50%, respectively, and then fall with increasing penetration.9,10

As shown in Figure 5, under modest decarbonization, high utilization of renewables may be achievable (transmission and thermal constraints neglected). Therefore, given lower costs, renewables alone could be cost effective for modest decarbonization. However, utilization was a dominant factor under deep decarbonization. Consequently, the scenarios where oversupply was limited were more cost effective despite the cost premium assumed for solar and DLC technologies. In other words, even though the assumed cost for wind power was less than that of solar, and solar was less than that of DLC, the low-emissions system whose generation mix was dominated by DLC and solar offered the lowest overall system level costs.

Moore Figure 5

FIGURE 5. System-level costs and marginal abatement costs of decarbonization scenarios


Cost-effective modest decarbonization requires a different strategy than cost-effective deep decarbonization. For satisfying modest decarbonization requirements, wind and solar generation alone may be cost effective. However, at scale, these options can create persistent oversupply episodes that are unlikely to be resolved by battery storage, let alone demand response. For deep decarbonization, electricity systems dominated by DLC and some solar generation achieve higher utilization rates with less storage. Rather than focus on the low-emissions technologies with the lowest LCOE, policymakers should take a long-term strategy and develop the technologies more likely to offer cost-effective deep decarbonization because of high system utilization. That means focusing research, development, demonstration, and deployment of carbon capture and storage in addition to nuclear, solar, and energy storage.


  1. Hourly ERCOT solar data was procured by modeling NREL’s Solar Advisor Model.11 It was assumed that energy was supplied by 10 disperse Texas solar sites with single-axis tracking.
  2. Wind supply is scaled based on hourly wind generation and demand in ERCOT in 2012.12
  3. The capacity cost of that natural gas is $330/MW-day8 and the marginal cost of its generation is $50/MWh.


  1. Ma, H., & Fu, L. (2011). Beyond the numbers: A closer look at China’s wind power success. Worldwatch Institute.
  2. ICF International & Shakti Sustainable Energy Foundation. (2014). Capacity value of wind generation in India – An assessment, in/wp-content/uploads/2014/02/Capacity-Value-of-Wind-in-India-Full-report1.pdf.
  3. Vorrath, S. (2015). Australian wind energy sets new record in July, gas-fired generation hits new low. Clean Technica com/2015/08/14/australian-wind-energy-sets-new-record-in-july-gas-fired-generation-hits-new-low/.
  4. Denholm, P., & Hand, M. (2011). Grid flexibility and storage required to achieve very high penetration of variable renewable electricity. Energy Policy, 39, 1817–1830.
  5. Solar Electric Power Association (SEPA). (n.d.). Calculating the value of energy storage,
  6. Safaei, H., & Keith, D. (2015). How much bulk storage is needed to decarbonize electricity? Energy and Environmental Science. DOI: 10.1039/c5ee01452b.
  7. S. Energy Information Administration. (2013). Updated capital cost estimates for utility scale generating plants,
  8. The Brattle Group. (2014). Third triennial review of PJM’s variable resource requirement,’s_Variable_Resource_Requirement_Curve.pdf
  9. National Renewable Energy Laboratory. (2006). Update: Effective load carrying capability of photovoltaics in the United States. NREL/CP-620-40068.
  10. Mills, A., & Wiser, R. (2012). Changes in the economic value of variable generation at high penetration levels: A pilot case study of California, LBNL-5445E. Berkeley, CA: Lawrence Berkeley National Laboratory.
  11. National Renewable Energy Laboratory (NREL). Solar Advisor Model (SAM),
  12. (2012). Generation,

The author can be reached at


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A Utility Overview of the U.S. EPA Clean Power Plan

By Frank Blake
Staff Engineer, American Electric Power

For more than 100 years, American Electric Power (AEP)—a major investor-owned utility delivering electricity to more than five million customers in 11 states in the U.S.—has provided affordable and reliable electricity that, in large part, has been based on the benefits of central-station fossil fuel generation and a robust transmission and distribution system. Throughout its history and especially over recent decades, AEP has sustained its industry leadership by diversifying its generation portfolio through increased use of natural gas, nuclear, wind, solar, and other generation resources, and by developing more efficient means to deliver power to customers. With one of the nation’s largest fleets of power generation resources, the largest transmission system in the country, and a rich history of technology innovation, AEP is uniquely positioned to offer insight on the capabilities of the existing electric system, as well as on the opportunities and challenges of transforming this infrastructure into the electric system of the future. This transformation of the utility industry will continue, especially in context with the requirements of the Clean Power Plan (CPP) regulation finalized by the U.S. Environmental Protection Agency (EPA or agency) in 2015 which is intended to “[accelerate] the transition to a clean energy future.”1

As this article was under preparation, the U.S. Supreme Court stayed the CPP, opting to allow legal challenges to be fully vetted before the requirements can be implemented. Regardless of the outcome of those legal challenges, a number of other drivers will continue to transform how electricity is generated, transmitted, and utilized in the U.S.

Blake-OpeningImage 2 column

AEP’s 600-MW John W. Turk, Jr. Power Plant in Arkansas, which went into operation in 2012, was the first plant in the U.S. to use ultra-supercritical coal combustion technology. The plant generates electricity more efficiently at higher temperatures, requires less coal, and produces fewer emissions to generate the same amount of power as existing coal units.


On 23 October 2015, the Federal Register published the final version of the EPA Clean Power Plan (i.e., CPP or Final Rule).2 The Final Rule establishes guidelines to reduce CO2 emissions from existing fossil fuel-fired steam (i.e., coal, gas, and oil) and natural gas combined-cycle (NGCC) electric generating units under Section 111(d) of the Clean Air Act. EPA estimates that, when fully implemented in 2030, the requirements will reduce CO2 emissions by approximately 32% compared to 2005 emissions from the sector.3 The CPP establishes two separate uniform national CO2 emission performance standards that are applicable to each existing fossil steam and NGCC unit subject to the rule. As an optional alternative, EPA also defined equivalent state-specific emission rate- and mass emission-based goals that individual states may adopt. Overall, the CPP is designed to achieve these goals by shifting electric generation from higher emitting fossil fuel-based generating units to lower or zero CO2-emitting resources.

The uniform national CO2 emission performance standards reflect EPA’s determination of the Best System of Emission Reductions (BSER) for reducing emissions from existing fossil fuel-based generating units. For the CPP, EPA determined that the BSER is comprised of three “building blocks” that collectively would result in certain emission reductions.

Building block 1 is based on emission reductions by heat rate (or efficiency) improvements that EPA concluded could be made cost-effectively through various equipment upgrades and the incorporation of best operating practices at existing coal-based generating units. EPA estimated that such measures, on average, could achieve heat rate improvements that ranged from 2.1 to 4.3% based on a plant’s existing operations.

Building block 2 is based on increased utilization of existing NGCC units and shifting generation away from existing coal-fired units. EPA assumed that all existing NGCC units can operate at a 75% annual capacity factor based on the net summer-rated capacity of these units.

Finally, building block 3 would reduce CO2 emissions through the deployment of new zero-emission renewable energy resources at their highest historic annual development rates during 2022 through 2030. Block 3 assumes that over 700 million MWh of potential renewable energy resources can be developed through 2030.

To determine the CPP emission reduction requirements, EPA relied upon unit-specific generation and emissions data from 2012 operations as a baseline. First, the agency aggregated the baseline information into three regions that represent the electric interconnection regions in the continental U.S. The building blocks were then applied separately to each region to determine region-specific fossil steam and NGCC emission rates. By selecting the least stringent value among these regional rates, EPA determined uniform national emission performance standards of 1305 lb CO2/MWh for existing fossil steam units and 771 lb CO2/MWh for existing NGCC units.4 EPA also established equivalent state-specific emission rate-based and mass emission-based goals that individual states may choose to adopt as the basis for their state plans. For context, Table 1 contrasts the 2030 final goals set by the CPP to the 2012 baseline for the top 20 emitting states.

Blake Table 1

TABLE 1. Summary of select final 2030 state goals5


The Clean Power Plan is structured to phase in emission reductions beginning in 2022 with the final requirements becoming effective in 2030. The 2022–2029 interim period is divided into three phases of increased reductions: phase 1 (2022–2024); phase 2 (2025–2027); and phase 3 (2028–2029). States can develop individual or multi-state plans to meet the emission guidelines, and submit those plans for approval by EPA. Final state plans or an initial submittal and request for extension must be submitted to EPA by 5 September 2016. An extension request, if approved, would allow a state two additional years to prepare a final state plan for submittal by 5 September 2018. EPA has one year to approve these state plans. If no state plan is submitted or EPA rejects a state plan, EPA will issue and determine a plan for that state.

Concurrently with the final CPP, EPA proposed “model rules” that states can use in fashioning their plans and that reflect the framework for any federal plan that would be issued by EPA. The model rules use the alternative rate- or mass-based state goals and rely on allowances or emission rate credits that could be exchanged through emission trading programs to facilitate compliance. States have the option to incorporate all or any portion of these model trading rules into their state plans. In addition, EPA has proposed a Clean Energy Incentive Program (CEIP) that would award additional allowances or emission rate credits as an incentive to deploy specific energy efficiency or renewable energy programs in 2020 and 2021, prior to the first compliance period for the CPP in 2022. However, because EPA is seeking comments on many aspects of the proposed federal plan and model trading rules, the options that will ultimately be available under a state plan or federal plan are not yet known.

Blake Powerlines 2 column Image

Fuel switching from coal to natural gas is one of the emission reduction blocks included in the EPA’s Clean Power Plan.


The design of the Clean Power Plan is not limited to measures that are achievable solely at individual fossil generating units, but incorporates activities occurring across the electric industry (e.g., actions within and outside the fenceline of affected generating units). Based on the stringency of the state goals and national emission performance standards, the availability of cost-effective emission allowances and emission rate credits through some form of a trading program will be essential for many, if not most, existing generating units to meet the requirements of the program and maintain adequate levels of operation.

However, several sources of uncertainty remain. The first is associated with the design of individual state plans and the content of the final federal plan. Whether states choose mass- or rate-based goals and how individual state plans are designed could limit the ability of sources to engage in trading programs within and across state boundaries. This will be a key factor in determining the feasibility and flexibility of compliance options. Cost-effective compliance options could be greatly enhanced by a process that facilitates exchanges between mass-based plans and emission rate-based plans.

Another consideration is whether the actions included as building blocks can be implemented so that adequate liquidity of allowances or emission rate credits materializes in a timely and cost-effective manner. Comments submitted on the proposed CPP by those that design, operate, and regulate fossil generating units raised significant concerns that EPA had greatly overestimated opportunities for heat rate improvements at coal units, the redispatch for NGCC, and the potential for and rate of new renewable energy development. Other comments expressed concern with the timing of the requirements, especially in context with maintaining grid reliability. EPA, in part, recognized these concerns when it extended the initial compliance period from the proposed 2020 start date to 2022 in the final rule.


A number of drivers continue to transform how electricity is generated, transmitted, and utilized in the U.S. These drivers include new environmental regulations, fuel availability and cost, power prices, the need to upgrade or replace existing infrastructure, as well as the development and cost-effectiveness of new technologies. This transformation already has resulted in a significant number of coal generating units being retired, new NGCC and renewable resources being developed, and the expansion of transmission infrastructure. While these trends reflect the concepts embedded within EPA’s building blocks, the degree of transformation to date is far from what will be needed to achieve the requirements of the Clean Power Plan. These trends will continue irrespective of the CPP. However, accelerating this transformation can only be done in a manner that ensures affordable and reliable electricity for the U.S.


  1. S. Environmental Protection Agency (EPA). (2015, 3 August). Obama administration takes historic action on climate change/Clean Power Plan to protect public health, spur clean energy investments and strengthen U.S. leadership. U.S. EPA,!OpenDocument
  2. Federal Register. (2015, 23 October). Carbon pollution emission guidelines for existing stationary sources: Electric utility generating units,
  3. Federal Register 80. (2015, 23 October). Carbon pollution emission guidelines for existing stationary sources: Electric utility generating units; Final rule, FR 64924.
  4. (2015, August). CO2 emission performance rate and goal computation technical support document for CPP final rule, pp. 18–19,
  5. (2015, August). CO2 emission performance rate and goal computation technical support document for CPP final rule, Appendices 3 and 5,


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The Paris Agreement and 21st Century Coal

By Milagros Miranda R.
Policy Director, World Coal Association

When Laurent Fabius, then France’s Foreign Minister, gaveled through the Paris Agreement on the evening of Saturday, 12 December, he signaled the end of four complex years of negotiations on climate change, and also the beginning of many more.

The Conference of the Parties (COP) of the UN Framework Convention on Climate Change (UNFCCC) met for its 21st session in Paris, from 30 November to 13 December. Even during the second week of negotiations, there was not much progress on the main issues at stake, in particular, differentiation between rich and poor countries, the long-term temperature or emissions reduction goals for mitigation purposes, and climate finance. In fact, those issues were possible deal breakers and remained contentious until the end of the negotiations. The trade-offs made on those key issues finally allowed for an outcome more than 24 hours after the conference was due to close.

UNFCCC leaders celebrate after the historic adoption of the Paris Agreement on climate change. Credit: Mark Garten/UN Photo/SIPA

UNFCCC leaders celebrate after the historic adoption of the Paris Agreement on climate change. Credit: Mark Garten/UN Photo/SIPA


The Paris Agreement marks the conclusion of the work of the Ad Hoc Working Group on the Durban Platform for Enhanced Action (ADP), which had a mandate “to develop a protocol, another legal instrument or an agreed outcome with legal force under the Convention, applicable to all Parties”.A The Paris Agreement is expected to enter into force in 2020.

The new agreement contains legal obligations for countries, particularly related to the review mechanism for scaling up ambition of the nationally determined contributions (now termed “NDCs” and previously known as Intended Nationally Determined Contributions or “INDCs”). It also encompasses flexibilities for its implementation by developing countries in the application of the principle of common, but differentiated responsibilities and respective capabilities (CBDR-RC).

The main elements in the Paris Agreement are summarized below.

Preamble and “Principle of Common Differentiated Responsibilities and Respective Capabilities”

The preamble of the agreement states that, in pursuit of the objectives of the convention, parties are guided by its principles, including the principle of equity and CBDR-RC, in the light of different national circumstances. This implies that all principles of the UNFCCC apply throughout the Paris Agreement and signifies that a differentiation exists between developing and developed countries. It is also clear that this differentiation should guide the implementation of the agreement, as the principle is explicitly referred to in its purpose section.

It is important to note that the Paris Agreement does not continue the UNFCCC classification of countries.B Rather, it differentiates between developed and developing countries in different sections of the text and includes references to special circumstances of least developed countries and small island developing states, but its commitments apply to all parties. Whether this leaves room to reflect further categorization of countries as per their upcoming levels of development remains to be seen.

India’s Prime Minister Narendra Modi addresses leaders from around the world at COP21. (AP Photo/Michel Euler)

India’s Prime Minister Narendra Modi addresses leaders from around the world at COP21. (AP Photo/Michel Euler)

Purpose. The Paris Agreement is more ambitious than most observers expected. It aims to keep global warming well below 2˚C pre-industrial levels, while recognizing a new aim, effectively a stretch target of 1.5˚C. It also aims to increase countries’ ability to adapt to climate change and foster climate resilience and to make finance flows consistent with the purpose of the agreement. This is particularly important because climate finance for mitigation and adaptation purposes is directly linked with the goal of the agreement.

Climate Finance. Until the end of negotiations, finance remained one of the most important challenges of the agreement—and a possible deal breaker. The main question was how to translate differentiation between countries. Developed countries insisted that some advanced developing countries with higher levels of economic growth (sometimes referred to as “emerging economies” or “emerging markets”) must also commit to financial contributions, so as to create a broader base of donors. Developing countries, on the other hand, applying the principle of CBDR-RC, strongly demanded that the Paris Agreement provide guidance for the delivery of new and additional financial resources, a clear roadmap for achieving the Cancun commitment from developed countries to mobilize $100 billion a year by 2020, and a pathway for scaling up mobilization of financial resources beyond the Cancun commitments.

Thus, in the final negotiated agreement, developed country Parties should continue to take the lead and should provide financial resources to assist developing country Parties with respect to both mitigation and adaptation while other Parties are encouraged to provide or continue to provide such support on a voluntary basis. Furthermore, developed countries shall report every two years on their financial contributions.

The Paris Agreement urges developed countries to fulfill their Cancun commitments to jointly provide US$100 billion annually by 2020 and calls on them to increase their financial contribution. Furthermore, the agreement states that countries shall set a new collective quantified goal from a floor of US$100 billion per year, taking into account the needs and priorities of developing countries.

Mitigation. This section of the Paris Agreement could also have been a deal breaker, as it contains many important contentious issues. While there were many options for explicit peaking emissions levels, or requiring between 40% and 70% net emissions reductions, the final agreement included neither specific levels of emissions reductions nor a specific time for achieving them, opting simply to call for global peaking of greenhouse gas (GHG) emissions as soon as possible. The agreement recognizes that it will take longer for developing countries to achieve this objective.

Adaptation. This section underwent more substantive development than in previous agreements, in particular the Kyoto Protocol, which was primarily focused on mitigation. The adaptation provisions call for enhancing adaptive capacity, strengthening resilience, and reducing vulnerability to climate change, with a view to contributing to sustainable development. It also includes the periodical update of an adaptation communication within the NDC review process.

Loss and Damage. The agreement recognizes the importance of averting, minimizing, and addressing loss and damage associated with the adverse effects of climate change. The Paris Agreement sets a voluntary, cooperative framework to address the issue, ruling out—as was so strongly called for by developed countries—any room for compensation or liability provisions.

The Paris Agreement also contains provisions concerning technology transfer, capacity building, transparency framework, and a global stocktake process of the implementation of the agreement, including climate finance contributions and a mechanism to facilitate implementation and to promote compliance with the agreement.


The basis of the success of the agreement lies within the design of the process leading into the Paris conference. Rather than setting top–down goals, such as were the basis of the Kyoto Protocol, countries were asked to submit their own intended climate contributions (i.e., INDCs) ahead of the meeting, hence forming a bottom-up process. That they could define what they propose to do and how they will do it gave countries confidence in the process.

More than 180 countries, including all the world’s major economies, submitted INDCs. The commitments made and the means to achieve them are as diverse as the economies of those nations. That means in some cases countries have chosen to focus on forestry, automotive emissions standards, scaling up renewable energy, efficiency in energy consumption, and/or reducing the role of fossil fuels in their electricity mix.

The Paris Agreement aims to be a turning point in the world’s response to climate change. Whether or not this becomes a reality will depend on the early entry into force of this agreement and its implementation by parties. The agreement will enter into force on the 30th day after the date on which at least 55 Parties to the Convention—accounting for at least an estimated 55% of the total global greenhouse gas emissions—have deposited their instruments of ratification, acceptance, approval, or accession.

The landmark agreement opened for signature on the 22 April 2016, in a high-level ceremony at the UN headquarters in New York. 175 countries signed the agreement and 15 of them also deposited their instruments of ratification. Thus, UN Secretary General Ban Ki-moon has called for the prompt entry into force of the agreement.

Miranda UN Image

A ceremony at the UN Headquarters in New York U.S. will signal the opening of the Paris Agreement for signature.

As the official signature book closes on 21 April 2017, we can anticipate more of those calls and expectations for the Paris Agreement to enter into force.

The agreement calls for a periodic increase in the level of ambition contained in the NDCs, through a five-year review process mechanism. Countries are accountable for this obligation as this is a legally binding element of the agreement.

In fact, the NDC review process may become even more important, as the agreement does not include an enforcement mechanism to hold countries accountable for their NDC. NDCs are therefore expected to be stepping stones for an ambitious implementation of the agreement. Indeed such an implementation relies on the successful execution of the NDC and its increasing ambition over the century through the five-year review cycle.

An initial assessment by the UNFCCC of the 147 INDCs submitted before the COP21 indicated that their aggregate effect will not meet the 2°C scenario.1 Others have suggested an aggregated effect of those INDCs ranging from 2.7°C to 3.7°C global warming temperatures.2 At the COP21, 195 countries agreed to the new agreement and 160 NDC representing 188 parties have been filed;3 nevertheless, those commitments are still insufficient to meet the 2°C scenario.

To achieve the 2°C or 1.5°C goal in the second half of this century would require drastic GHG emissions reduction and significant investments concerning infrastructure deployment and low-emissions technologies. However, the responsibility for a successful outcome does not rely on government actions only, but on those of all actors. The new deal marks a global challenge for both public and private sector at the local, national, and international level to work for a low-carbon or zero-carbon future.

The Paris Agreement is expected not only to accelerate the transition toward a low-carbon economy, but also the achievement of the UN 2030 Agenda for Sustainable Development4 and the Implementation of the Addis Ababa Action Agenda.5


In the implementation of the NDCs, countries will need support to achieve their mitigation objectives while continuing to grow and develop. This is particularly important for developing countries.

We need to remember that 1.1 billion people in the world lack access to modern electricity and double that number lacks access to clean cooking facilities.6,7,C Many developing countries, particularly in emerging and developing Asia, have identified a role for advanced coal technologies in their NDCs8—because, for many countries, affordable and reliable electricity is the foundation of their economic development. These economies are industrializing and urbanizing at a rapid rate. Thus, affordable, reliable electricity is essential and, for many, it is coal that will continue to provide that electricity.

It is certain that coal will continue playing a role in the world’s energy mix.9 IEA’s special report on Southeast Asia highlights that coal is the fuel of choice in the region, due to its relative abundance and affordability.10 It also indicates that the region’s energy demand is projected to grow by 80% in 2040 and in terms of electricity demand.

Energy generation and consumption efficiency are key components of sustainable development. As countries will continue using affordable and available resources such as coal and other fossil fuels, it is critical to support them in achieving energy access and economic growth with the lowest possible level of GHG emissions. This is doable with the use of 21st century technologies such as high-efficiency, low-emissions (HELE) coal technologies that increase the efficiency of power generation and allow for substantial emissions reductions and CCS that can achieve emissions reductions of more than 90%.


Advanced coal technologies, and the associated technology transfer, are imperative to the implementation of the Paris Agreement.

The IEA’s Energy and Climate Change report identified HELE technologies as “essential features of strategies to reconcile future energy use with global aspirations to tackle climate change”.11

If the world wants the Paris Agreement to be successful in its implementation, it is imperative to support countries’ efforts to reduce carbon emissions through HELE coal technologies and CCS/CCUS. There is no time to lose.


  1. Article 2 of COP 17 Decision 1/CP.17: Establishment of an Ad Hoc Working Group on the Durban Platform for Enhanced Action
  2. The Kyoto Protocol classified countries into Annex I countries (industrialized countries that were members of the OECD (Organisation for Economic Co-operation and Development) in 1992, plus countries with economies in transition (the EIT Parties), Annex II countries (OECD members of Annex I, but not the EIT Parties) and non-Annex I countries (mostly developing countries). For more information see int/parties_and_observers/items/2704.php
  3. The UN Sustainable Energy for All webpage indicates 1.3 billion people without access to electricity, but updated information issued by the organization indicates that the number is now 1.1 billion people in energy poverty (See: Similar information is provided by the World Bank:


  1. United Nations Framework Convention on Climate Change (UNFCCC). (2015, 30 October). Synthesis report on the aggregate effect of the Intended Nationally Determined Contributions: Note by the Secretariat (FCCC/CP/2015/7), int/resource/docs/2015/cop21/eng/07.pdf
  2. United Nations Framework Convention on Climate Change (UNFCCC). (2015, 30 October). Synthesis report on the aggregate effect of the Intended Nationally Determined Contributions: Note by the Secretariat. Technical Annex. (FCCC/CP/2015/7), int/files/focus/indc_portal/application/pdf/technical_annex_-_synthesis_report_on_the_aggregate_effect_of_the_intended_nationally_determined_contributions.pdf
  3. (2016). INDC portal,
  4. United Nations (UN). (2016). Transforming our world: The 2030 agenda for sustainable development,
  5. (2015). Addis Ababa Action Agenda of the Third International Conference on Financing for Development, UN document (A/Res/69/313),
  6. (2013). Sustainable energy for all,
  7. International Energy Agency (IEA). (2013). World energy outlook 2013,
  8. World Coal Association. (2015, 2 December). INDCs—Low emission coal technology pledges,
  9. (2015) World energy outlook,
  10. (2015). Southeast Asia energy outlook 2015: World energy outlook special report,
  11. (2015). Energy and climate change: World energy outlook special report 2015,


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