Category Archives: Strategic Analysis

New British Deep Mine to Deliver 50-Year Coking Coal Project

By Tony Lodge
Research Fellow, Centre for Policy Studies, London

The British government’s plan to ban all coal-fired power stations by 2025 has made headlines around the world.1 Many will now close early and, with that closure, the mining, coal handling, and import facilities that once dominated British ports will become redundant. Though now in decline, this formerly large thermal coal dependency supported many deep and surface mines across Britain and supplied thermal coal internationally. Britain’s electricity supply industry is now looking to combined-cycle gas turbine (CCGT) plants, renewable energy, and new nuclear power plants in its quest to meet ambitious CO2 reduction targets.

But the end of thermal coal mining and coal-fired electricity generation in Britain risks overshadowing significant new coal mining ambitions to supply Europe’s growing coking coal demand. The British metallurgical coal (also known as hard coking coal) resource is significant and of high quality. It is this prospect, as well as the growing markets in the recovering European steel-making sector, that has prompted a pioneering British project to propose and seek to develop Britain’s first new deep coal mine for 30 years.

West Cumbria Mining (WCM) is at the forefront of plans to produce some of the finest hard coking coal in the Western Hemisphere with production planned to start in 2020. Importantly, this coal production will not face the UK government’s high carbon taxes that have penalized thermal coal burning power plants as it will be used in the steel-making sector. This distinction is important; this is not an energy-related project, but rather a 50-year mining operation to supply the steel- and iron-making industries with high-quality metallurgical coal.

A visual image of the proposed new mine’s surface buildings

The timing of this project is important. Morgan Stanley has declared coal to be “the spectacular turnaround story of 2016”.2 On the back of Chinese coal production caps, coal prices have soared with coal vastly outperforming other commodity markets. The value of coking coal shipped from Australia, the world’s top exporter of the industrial commodity, had tripled by December 2016 to more than US$300 a metric ton for the first time since 2011. Macquarie forecasts coking coal to stabilize at around US$200 a ton, with global output of metallurgical coal remaining in high demand as steel mills source more supply.

WCM has secured the rights to extract metallurgical coal from the rich offshore coal seams of the Cumbrian coast in the North West of England. The company, led by CEO Mark Kirkbride, plans to use two abandoned drift tunnels constructed to access a former anhydrite mine. These will connect the offshore coal resource with an abandoned industrial site onshore where modern, low-profile coal treatment and handling buildings will be sited. An underground conveyor will move coal to a rapid rail loader situated on the existing coastal railway less than a mile from the site.

The proposal is ambitious both in its design and output targets. It will utilize state-of-the-art technology and mining methods to achieve production of around 3 million tonnes per annum, aiming to deliver up to 2.5 million tonnes of saleable metallurgical coal product a year.A The target seams are High Volatile Hard Coking Coals (HV HCC). They are sought by European steelmakers due to their excellent furnace performance characteristics (very high fluidity) and extremely low ash and phosphorous content.

Planning consent is being sought in spring 2017 from local government bodies to take the initial development of the project to the next phase of what will be one of the major metallurgical coal mining operations in Europe. Local political figures strongly support the project, which will create more than 510 skilled mining, engineering, and supporting jobs.B

The Cumbrian coast has a rich mining history

Bad headlines dominated the European steel sector in 2015 with prices at record lows, but there are now signs of growing stability and rising prices.3 WCM’s product would be a core component for incorporation within a blend of other types of metallurgical coals to produce suitable coke for use in iron and steel production. Indeed, it is extremely similar in character to the premium hard coking coals mined in the eastern U.S. and currently imported and consumed by the UK and European steel industry. The WCM coal is the equivalent of US HV-A material, a key market benchmark coal for pricing purposes.C

Consequently, the future global market outlook for HCC demand is key. World and European steel demand is set to grow significantly by 2030, particularly in the construction sector. The forecast global HCC demand to meet such growth is unlikely to be met by operating and proposed new metallurgical coal mining projects. There is a real risk of a future global shortage in HCC supply with so few new mining projects being proposed.D

Forward planning by WCM has already identified a sea freight export facility in North East England, where its metallurgical coal can be exported easily and quickly from the deep-sea wharf Redcar bulk terminal facility into Europe. This was until recently part of the vast SSI steelworks that became an early victim of the collapse in world steel prices. This coal loading berth at Redcar is a direct 100-mile rail journey from the proposed mine. WCM will also seek to supply metallurgical coal to British steelworks which are showing signs of recovery following the recent slump in output and prices.

The mine’s development and operation will be undertaken by bolter-miners and remote operated continuous miners, working a partial extraction run-out and pocket retreat mining method. WCM argues that this method offers the greatest flexibility and can respond quickly to prevailing ground conditions to maintain consistent production levels, especially where multiple mining sections are operated.

Importantly, given local environmental considerations, the mine will have state-of-the-art low-profile surface buildings to ensure minimum visual impact. This will be in stark contrast to the large headstock and winding gear of traditional mine buildings, which can still be seen in the area where they have been preserved as a monument to the area’s industrial legacy. There will be no tips of mine discard, as this will be transported from the site by rail to a quarry where it will be crushed and screened prior to use as fill material on construction and other such projects.

Although the UK is turning away from thermal coal to generate electricity, this new project is attracting considerable interest as curious observers learn that not all coal is the same. As readers of this journal know only too well, there are various types, qualities, and consequently different markets.

As coal’s thermal markets come under greater policy strain, projects like this allow the fuel a valuable platform to demonstrate its alternative and varied uses. Consequently, it deserves the attention, focus, and support it is receiving.


  • A. Author interview with WCM CEO Mark Kirkbride, December 2016.
  • B. WCM has met and is working closely with Jamie Reed, local Member of Parliament, local councillors, and policy leaders.
  • C. Key parameters and qualities of WCM coal are equivalent to US High Volatile ‘A’ Hard Coking Coal type.
  • D. Analysis and forecasts provided to WCM by Wood Mackenzie.


  1. Reed, S. (2015, 18 November). Britain calls for closing of coal-fired power plants by 2025. New York Times,
  2. Hoyle, R. (2016, 11 November). Coal prices on fire. The Wall Street Journal,
  3. Staff. (2015, 9 November). Steel industry calls for EU action on Chinese imports. BBC News,


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Phasing Out Coal-Fired Power Plants in Alberta by 2030: Recent Developments

By Babatunde Olateju
Manager, Carbon Capture and Utilization, Alberta Innovates
Surindar Singh
Executive Director, Clean Technology, Alberta Innovates
Jamie McInnis
Portfolio Manager,
Reservoir Simulation and Modelling Research Group,
University of Calgary


The province of Alberta, located in Western Canada (see Figure 1), is regarded as the pillar of Canada’s energy economy. It is home to the third largest oil reserves in the world,1 produces 68% of Canada’s natural gas,2 holds significant renewable energy resources, and is the site of Canada’s first commercial windfarm.3 Yet the most abundant fossil fuel energy resource in Alberta is coal. The energy content of coal in Alberta is greater than the energy content of natural gas and oil combined, including the oil sands.4 Coal-bearing formations underlie 304,000 km2 or 46% of Alberta’s total area, making the formations larger than the United Kingdom. Alberta’s coal resource is estimated to be greater than 2 trillion tonnes.4

FIGURE 1. Location of Alberta in Western Canada

Since the deregulation of the Alberta electricity market in 1996, electricity supply has been dominated by coal. It accounted for 51% of electricity generation in 2015 and 39% of the current generation capacity in the province.5 Alberta’s electricity sector accounted for 17% of its greenhouse gas (GHG) emissions6 in 2013. Coal-fired plants are the primary source of these emissions. Against this backdrop, a newly elected provincial government in May 2015 brought a change to the political leadership and also to the provincial climate change policy. In June 2015, the provincial government introduced bold new changes to the Specified Gas Emitters Regulation (SGER).A The emissions levy was increased from the original $CDN15/tonne (US$11.19) to $CDN30/tonne (US$22.13) by 2017.7 Additionally, a higher performance criterion was put in place: By 2017, emissions intensity must be reduced by 20% from an established baseline, as opposed to the original target of 12%.7 In November 2015, the government articulated the following points relevant to the electricity sector, as part of its Climate Leadership Plan:

  • Mandated phaseout of pollutant emissions from coal-fired plants by 2030.
  • Coal-fired plants will pay $CDN30/tonne for emissions, based on an emissions performance standard, by 2018.
  • Replacement of existing coal-fired plant capacity (6299 MW), with about 4200 MW of renewables (two-thirds of existing coal capacity) and 2100 MW of natural gas (one-third of existing coal capacity), will be achieved by 2030.
  • Thirty percent of Alberta’s electricity generation (MWh) will be from renewables by 2030.8

Keep Hills 3 coal-fired power plant

In November 2016, plans for a capacity market (by 2021) to complement Alberta’s current energy-only market system were announced.9 In the energy-only market system, generators are only compensated for the actual amount of energy (MWh) supplied to the grid. The introduction of a capacity market is intended to strengthen the reliability of supply and stabilize electricity prices, while providing an opportunity for generators to earn revenue by making generating capacity (MW) available to be dispatched when required.

In light of this new era in Alberta’s electricity market, this article aims to address the following questions: (1) What do these changes mean for coal-fired power plants in the context of Alberta’s electricity market? (2) What are the key determining factors for the successful phaseout of coal and what are the implications? (3) Are we living in a post-coal era or is a future coal resurgence possible?

To address these questions, we first need to understand the current basic Alberta economics of electricity generation as it pertains to coal-fired plants.


In Alberta’s wholesale electricity market, the price is determined by supply and demand forces; a price floor of $0/MWh and a price celling of $999/MWh are set in place. The mechanism to determine the price of electricity involves the Alberta Electric System Operator (AESO) using a merit-order system where generators offer bids to supply electricity at various prices (often related to their marginal cost of electricity generation). The AESO dispatches supply bids in ascending order of costs—i.e., the least-cost bid is dispatched first, and so on—to service demand. The last bid dispatched within a one-minute time frame sets the system marginal price (SMP). Finally, the average of the SMP for each minute in a given hour sets the hourly pool price. The hourly pool price is used to compensate all generators that supply electricity in a particular hour.10 An exception occurs when a supply bid was dispatched for only part of an hour, at a price greater than the average price in that hour. In such a case, the AESO pays the supply bid price for that portion of that hour.10

The economics of operating coal-fired plants in Alberta are quite challenging for several reasons. First, to coincide with the oil price shock in the last quarter of 2014, electricity demand weakened (about two-thirds of Alberta’s electricity demand is industrial) as new supply capacity was about to be commissioned.B As a result, the pool price began a steep descent and reached levels (< $CDN20/MWh) not seen in two decades.11 Second, sustained low natural gas prices make gas plants a competitive option relative to coal, particularly for baseload operations. Third, the April 2015 introduction of wind power plants into the merit-order system10,12 added downward pressure on the pool price. Wind plants have near-zero marginal costs and can afford to bid into the market at low energy prices that are uneconomic for coal. With significantly increased renewable penetration anticipated (plants with generally low marginal costs), the downward pressure exerted on prices will likely increase in magnitude. Last, the changes to the SGER resulted in a material increase in the cost of compliance for coal power plants; it is expected to rise from $CDN2/MWh in 2015 to $CDN6/MWh in 2017.13


The difficult economic circumstance of coal-fired plants is not unique to Alberta; it is indicative of a broader trend in electricity markets across North America. For example, both the Electric Reliability Council of Texas (ERCOT) and wholesaler PJMC have low natural gas prices. Additionally, the increased penetration and cost-efficiency of renewables such as wind and solar are reducing the market share and competitiveness of coal significantly.14 A successful phaseout of coal by 2030 must be done in a planned, orderly fashion to ensure the reliability of the grid, affordability of energy prices, and the continued downward trend of GHG emissions in the future. This is dependent on several factors that serve as key determinants of success in the impending phaseout.

Striking a Delicate Balance

The rate at which coal is phased out vis-à-vis the rate at which gas and renewable generators are phased in is a delicate balance that needs to be carefully struck.

There are many implications to this careful balancing act. The phaseout of coal will result in gas becoming the dominant baseload energy generation option. Moreover, due to the intermittency of renewable generators, natural gas peaking plants will increasingly be relied upon to firm up supply; these peaking plants will have attendant GHG emissions during their operation. With this in mind, there is an opportunity for technological innovation that will facilitate the penetration of utility-scale low-carbon energy storage technologies (e.g., pumped hydro, redox flow batteries, sodium sulfur batteries, etc.) in Alberta’s electricity market. Energy storage has the potential to mitigate the intermittency of renewables, without the attendant operational GHG emissions aforementioned. Gas being the anchor baseload generator will also lead to the increased exposure of the grid to the dynamics of natural gas prices which, historically, have been quite volatile. Furthermore, the concentration of electricity supply from one fuel type, i.e., gas, is likely to create the same challenges of phasing out a dominant generation option such as coal. From a GHG perspective, gas-fired plants of today are likely to be the coal-fired plants of tomorrow, as our energy economies become increasingly GHG averse. A portfolio approach that ensures sufficient diversification of the energy supply mix will provide stability for the grid in the future.

The Incentive to Build

In light of the coal phaseout, the need for additional renewable capacity in Alberta’s electricity market cannot be overstated, if the climate leadership objectives8 are to be realized. However, in a low-price electricity market, the incentive to build additional capacity is practically nonexistent. Addressing this issue is quite complex and presents several challenges. The Alberta government has introduced a renewable electricity incentive program (to be carried out by AESO) that will provide support for the addition of 5000 MWD of renewable capacity by 2030. The details of the first auction (400 MW of renewable capacity) have been released by AESO.15 Some key features of the auction include: a competitive bidding process; use of existing transmission or distribution infrastructure; renewable credits provided will be indexed to the pool price, i.e., a contract for difference; and plants must be operational by 2019. As reported by AESO,15, the indexed renewable credits create three possible scenarios that are a function of the (winning) bid priceE in the auction and the pool price of the market.

In the first scenario, if the pool price is lower than the bid price—the government pays the difference to support the project. Second, if the pool price is equal to the bid price—there are no payments made by the government. Last, if the pool price is higher than the bid price—the plant owner pays the government the difference. Going forward, the competitive nature of this entire 5000-MW program and the effective apportioning of the risks involved will be crucial in creating a favorable investment environment, while also making electricity prices affordable.

Genesee 3 Coal Power Plant

Accessing the Opportunity of Change

Alberta’s electricity market is in a state of transition. This fluid state of the market has included competitive auctions for renewable energy generation, along with the planned addition of a capacity market by 2021. The capacity market, depending on the way it is designed, holds significant promise not just in enhancing the reliability of supply, but in incenting innovation. Apart from “traditional” generators (gas, hydro, wind, solar, biomass), nontraditional generators, which have baseload and load following functionalities, with low to zero GHG emissions during operation, are likely to benefit significantly from the revenue certainty a capacity market provides in a carbon-constrained electricity sector. Nontraditional technologies that hold some potential in this regard include commercial technologies such as geothermal power, as well as emerging technologies including next generation small modular nuclear reactors. These technologies create opportunities for innovation and the mitigation of greenhouse gas emissions from the electricity sector.

That said, whether Alberta’s future electricity market will encompass the nontraditional technologies as legitimate participants will become clearer as time progresses.


Some would argue that coal in Alberta has no future and is slowly becoming a relic of the past. This argument is founded on a number of factors, but often, it does not consider that coal is a resource, not just a fuel for electricity. Coal as a resource will remain the same; recovery and production technologies will evolve. The evolution of technology in response to the economic, environmental, and social constraints will be a crucial determinant of the question: Will coal be back? In this light, several technological trends and opportunities are worth highlighting.

In the near term, before the 2030 phaseout, the co-firing of coal with other carbon-neutral feedstock such as biomass, economics permitting, provides an opportunity to lower the cost of compliance of coal-fired plants (due to the reduced GHG emissions) and utilizes potentially stranded coal assets.

The technological development and maturity of carbon capture and sequestration as well as underground coal gasification, considering their cost effectiveness, environmental performance, and social acceptability, has the potential to introduce new life into coal for the production of fuels; for example, hydrogen, synthesis gas, dimethyl ether, and others. Carbon conversion technologies that transform CO2 into a value-added product such as fuel or cement introduce additional potential for the environmentally sustainable use of coal. Finally, coal can be used in non-combustion applications. Current efforts are being made to extract rare earth metals from coal,16 which enable crucial functionalities in renewable technologies and other technology platforms such as consumer electronics and aerospace. New materials produced from coal, such as carbon foam,F are alternative uses of coal that could be sustained in a low-carbon era.


For the phaseout of coal to be conducted successfully without adverse impacts on Alberta’s grid, it must be undertaken in a careful, deliberate, and orderly manner. Despite the need for new capacity to come online to replace coal-fired plants, the effective apportioning of the risks involved should be carefully considered. The future concentration of supply on one fuel type (i.e., gas), with limited diversification of the supply mix, is likely to create the same challenges currently being experienced in phasing out coal-fired plants, as energy economies become increasingly GHG adverse. Finally, we must remember that technology rose to the occasion to find ways to access and utilize coal during the Industrial Revolution. Technological innovation will be vital if coal is to have a place in an energy future with heightened environmental consciousness.G


  • A. The SGER was originally introduced in 2007. It required large emitters (≥100,000 tonnes CO2e/yr) to reduce their emission intensity against an established baseline, earn emission offsets or performance credits, or pay a levy of $CDN15/tonne into a Climate Change and Emissions Management Fund. The 2007 SGER is available at:
  • B. Alberta’s largest gas-fired plant (800 MW of capacity) began commercial operation in March 2015.
  • C. PJM is the wholesale electricity market for all or parts of several northeastern states in the U.S. More information is available at:
  • D. More information on the Renewable Electricity Program is available at:
  • E. The bid price is, ideally, the lowest possible price the project developer can accept to advance the project.
  • F. CFOAM® carbon foam and CSTONE are enabling technologies for a host of next-generation material systems and components. More information is available at:
  • G. The views expressed are that of the authors and do not represent the opinions of Alberta Innovates or the University of Calgary.


  1. Canadian Association of Petroleum Producers (CAPP). (2016). Canada’s petroleum resources,
  2. Alberta Energy Regulator (AER). (2016). ST98-2016: Alberta’s energy reserves 2015 and supply & demand outlook 2016–2025. Executive summary,
  3. Canadian Wind Energy Association (CANWEA). (2016). Wind energy in Alberta,
  4. Alberta Innovates Energy and Environment Solutions, Canadian Clean Power Coalition. (2013). In-situ coal gasification in Alberta—Technology and value proposition: Final outcomes report,
  5. Alberta Energy. (2016). Energy statistics: Electricity supply,
  6. Government of Alberta. (2016). Alberta’s current emissions,
  7. Osler, Hoskin & Harcourt LLP. (2016, 15 April). Carbon and greenhouse gas legislation in Alberta,
  8. Government of Alberta. (2016). Climate Leadership Plan—Ending coal pollution,
  9. Alberta Electric System Operator (AESO). (2016). Capacity market transition,
  10. EDC Associates Ltd. (2016). Quarterly forecast update – Second quarter 2016,
  11. Varcoe, C. (2016, 9 July). Alberta’s power market in turmoil as prices hit 20-year lows and demand falls. Calgary Herald,
  12. Market Surveillance Administrator. (2015). Market share offer control, 2015.
  13. Leach, A., & Tombe, T. (2016, August). Power play: The termination of Alberta’s PPAs. University of Calgary, School of Public Policy Communique, 8(11),
  14. Schlissel, D.A. (2016, 16 September). A sustained coal recovery? “When you get there, there’s no there”. Institute for Energy Economics and Financial Analysis,
  15. Alberta Electric System Operator (AESO). (2016). First competition,
  16. Rozelle, P.L., Khadilkar, A.B., Pulati, N., Soundarrajan, N., Kilma, M.S., Mosser, M.M., Miller, C.E., & Pisupati, S.V. (2016). A study on removal of rare earth elements from U.S. coal byproducts by ion exchange. Metallurgical and Materials Transactions, 3, 6–17.


The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.
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Dubai: Pioneering a Sustainable Energy Model for Sustainable Development and Security of Supply

By Taher Diab
Senior Director of Strategy & Planning, Dubai Supreme Council of Energy

The Emirate of Dubai is one of the fastest growing cities in the world and a regional hub for tourism, logistics, and finance. The Dubai government is implementing an innovative strategy to manage demand, diversify fuel sources, secure its energy supply, and foster green growth. One strategic aim is to continue to fuel Dubai’s economic growth and maintain its regional and global prominent position.

Dubai’s installed generation capacity is about 10 GW. The main source of this power is from imported natural gas, which makes Dubai a net energy importer. Therefore, energy security is a high priority with forecasted electricity demand for the next decade projected to increase annually by 5–6%. In addition, the Emirate is pursuing a sustainable development path and plans to use clean energy technologies.

The economic success story of Dubai demonstrates how it managed to design and implement an energy strategy that captures the key levers driving its economy: energy security, demand-side management, and sustainable growth. Dubai is a living model of a coherent and cohesive energy strategy that meets future energy needs through an optimal energy mix that delivers affordable, sustainable, and clean energy to its citizens and residents.


The Emirate’s energy model originates from the Dubai Integrated Energy Strategy (DIES) 2030, which was launched in 2011 by the Dubai Supreme Council of Energy (DSCE) and is reviewed periodically. The DIES strategy was recently extended until 2050 with a detailed roadmap on how to achieve various CO2 free generation source targets by 2030 and 2050 (Figure 1).

FIGURE 1. Dubai Integrated Energy Strategy 2050.

The strategy builds on a world-class regulatory framework to accelerate the diversification of the energy mix, ensure security of supply, and facilitate effective demand-side management, as shown in Figure 2 with Dubai’s Integrated Energy Strategy up to 2030.

FIGURE 2. Dubai Integrated Energy Strategy – 2030.

The DIES includes the following elements:

    • Governance and Policies: To achieve the DIES targets, the policy and regulatory regime in Dubai’s energy sector has been overhauled. New principles such as public–private partnerships have been put in place to increase market participation in key projects, including clean coal and solar power generation. The regulatory framework for district cooling and energy service companies (ESCOs) is also supporting the implementation of DIES 2030.

Dubai is undergoing an energy transition.

  • Energy Efficiency and Demand Reduction: Demand reduction through energy efficiency is a focus of Dubai’s policy interventions to rationalize the use of power and water. The demand-side management (DSM) strategy has led to nine different programs and technical levers for energy efficiency and demand reduction. This has resulted in savings in capital, operational, and opportunity costs (as discussed in the next sections).
  • Energy Security and Sustainable Cost of Gas: Diversification of Dubai’s energy sources is a key focus of DIES 2030. This has led to several projects to increase future energy security including the proposed building of a clean coal power plant, solar, and encouragement of Independent Power Producer (IPP) projects. The Mohamed bin Rashid Al Maktoum Solar Park is an example of Dubai’s commitment to renewable energy. Other important elements in development include the use of imported nuclear energy, clean coal, waste-to-energy, hybrid and electric vehicles, and the distributed solar program (Shams Dubai).
  • Financial Mechanism and Capacity Building: DIES 2030 has launched measures and projects targeting DSM, renewable power, energy service contractors, Green Building Codes, and energy efficiency technologies. Financial mechanisms, such as the announced Dubai Green Fund currently under development, will encourage deployment of clean energy technologies in Dubai.


A market-based approach using public–private partnerships (PPPs) has been developed to meet the fast-growing demand for infrastructure in Dubai. The PPP approach leverages funding sources and helps balance the risk between the government and private investors. By fostering partnerships with leading international firms in clean energy, Dubai also aims to expand its local capacities through transfer of knowledge and skills.

Since the DSCE’s inception, it has rolled out a series of step-by-step regulatory reforms and policies to open the electricity market for independent power producers. This involved establishing the Regulatory and Supervisory Bureau (RSB) for the electricity and water sector in 2010. The RSB’s responsibilities include licensing of new entrants in the power sector.

One of the pillars of the DSEM, and a crucial factor in transforming Dubai’s energy market, was the review of the electricity and water tariff structure. In 2011, the Dubai Electricity and Water Authority (DEWA) introduced cost-reflective tariffs to incentivize lower consumption and more efficiency in the use of electricity and water. This sent positive signals to clean energy investors as the market became economically attractive for clean technologies, allowing for successful PPPs. Dubai’s robust regulatory framework provided investors with three key elements for long-term investment: transparency, longevity, and certainty.


After evaluating the options to provide supply security of supply for Dubai, the government decided to shift from dependency on fossil fuel and to increase the renewable energy share. This culminated in a target of 25% of clean installed capacity by 2030 and 75% by 2050 using CO2-free generation sources. To achieve these targets, Dubai is taking progressive strides to integrate solar power into an energy mix portfolio that is currently dependent mainly on imported natural gas.

The robust regulatory framework and commercial terms have attracted international and regional investors resulting in the lowest levelized cost of electricity (LCOE) for 200 MW at 5.64 US cent/kWh and recently DEWA announced an 800-MW solar photovoltaic (PV) power plant at 3.0 US cent/kWh. This development marked a turning point in the journey to diversify Dubai’s energy mix and demonstrated the value proposition of strategic PPPs for procuring energy at a record low price.

The transformation of the energy sector in Dubai is also occurring on the customer side. Residents can generate their own electricity using solar panels that can also feed extra energy to the Dubai power grid. This step will gradually transform the consumers to “prosumers”, a term used to describe consumers that also generate part of their own energy consumption. Dubai currently deploys a simple net-metering system wherein customers achieve savings by generating their own electricity.


For Dubai to diversify its energy mix, a decision was made to integrate clean coal to reduce dependency on imported natural gas and meet rising energy demand. Several reasons led to the decision to develop coal as an energy source. Coal is highly competitive with its low prices, dispatchability, and baseload compatibility. In addition, the combination of technological advances that allows both for higher efficiencies and reduced pollutants and emissions make it an ideal option to meet Dubai’s future energy needs.

In fact, Dubai’s commitment to a clean future stipulates the clean energy targets of the DIES 2050 strategy do not include clean coal without carbon capture and storage (CCS). Dubai has some of the most stringent emission standards and limits in the world for flue gas emissions. The deployment of clean coal technology will require meeting aggressive emissions and international environmental standards set for flue gas emissions. The limits are stricter than those in the Industrial Emissions Directive (IED) of the European Union and in the International Finance Corporation (IFC) guidelines. Dubai’s clean energy targets also include achieving CO2-free generation sources of 25% of its installed capacity in 2030 and 75% in 2050.

In 2016, Dubai awarded the first phase of the Hassyan Clean Coal Power Project comprising four 600-MW units. The ultra-supercritical technology to be deployed will aim for 50% high heating value (HHV) efficiency compared to only 35% efficiency in the current pulverized coal-fired plants. The first 600-MW unit will be commissioned in 2020. The full project size is 2400 MW; it will be the first clean coal power plant in the Gulf Cooperation Council (GCC) region. The electricity from the coal-fired power plant will be utilized during the high peak demand periods of the summer season to ensure security of supply at a reasonable cost.

Dubai has developed attractive commercial terms to secure the lowest levelized cost of electricity (LCOE) of about 4.5 US cent/kWh for the Hassyan project based on an IPP procurement model on a build-own-operate (BOO) basis. The project is 78% debt and 22% equity financed. This IPP model also fosters partnerships with leading international firms in clean energy, leverages funding sources, and helps balance the risk between the government and private investors.


DIES 2030 also has an objective to reduce 30% of Dubai’s energy demand from the current business-as-usual scenario. To achieve this reduction by 2030, a detailed DSM strategy for electricity and water has been implemented, which is the first of its kind in the region. The DSM strategy has opened up new business opportunities for sustainable and efficient businesses by outlining policies, regulations, awareness schemes, technologies, and finance schemes.

The strategy is based on nine programs with a specific database, reduction targets, and enablers to influence behavior and encourage well-thought-out measures. To ensure that the measures are effective, the government has engaged key stakeholders for consultation on the proposed programs, reduction measures, and timeline with a clear roadmap targeting 30% consumption reduction of water and electricity by 2030. The stakeholders’ engagement and global benchmarking will provide information and knowledge in the following areas: building regulations, building retrofits, district cooling, standards and labels for appliances and equipment, water reuse and irrigation, outdoor lighting, change of tariffs, demand response, and distributed solar.


To accelerate the uptake of hybrid and electric vehicles (EVs), the Emirate established the Green Mobility Initiative to lead the world in becoming more sustainable using smart technologies. The initiative complements the spirit of Dubai Plan1 2021 by providing alternative modes of transportation that reduce fuel usage and CO2 emissions. Road transportation is the third largest source of Dubai’s greenhouse gas (GHG) emissions. This initiative is an important contributor to Dubai Carbon Abatement Strategy 2021, which aims to reduce carbon emissions by 16% in 2021 compared to the business-as-usual scenario in 2021.

The Dubai Supreme Council of Energy and its entities have developed a comprehensive approach founded on the principle of “leading by example”. A detailed analysis was undertaken by the government of the market potential of hybrids and EVs. Based on this analysis a decision was made that the government vehicle fleet would be 10% hybrid or EVs by 2021.2

In addition to creating a market for hybrids and EVs, leading by example will enable the government to build the learning curve necessary to expand the deployment of such vehicles in the arid climate of Dubai. The Road and Transportation Authority (RTA) has already demonstrated the successful use of hybrid vehicles. The RTA3 employed over 140 hybrid taxis in 2015 and reported that around 30% fuel savings were achieved and found no performance challenges with the vehicles. The RTA is currently planning to convert 50% of its fleet to hybrid taxis by 2021 and is monitoring feasibility of hydrogen cell vehicles based on recent advancement in this technology.


In a short time, the Emirate has created a platform to find solutions for energy challenges by development of specific programs and projects. The first-in-the-region Dubai Carbon Abatement Strategy 2021 details programs that integrate alternative and renewable energy to diversify Dubai’s generation mix. This strategy will allow the Emirate to manage its energy demand, to increase efficiency, and to develop sector-based GHG reduction targets.

To design a performance-based program for carbon abatement, the strategy defined major sectors contributing to carbon emissions, referred to as “high-impact sectors”. Based on the carbon emissions profile for 2011, these sectors are power and water, manufacturing, road transportation, and waste. An unpublished technical evaluation of the emissions reduction potential for these high-impact sectors was carried out with the support of the Dubai Carbon Centre of Excellence, resulting in a target of 16% reduction of GHG by 2021 in comparison with the business-as-usual estimations for the same year.

In 2015, members of the Dubai Carbon Abatement Strategy saved 5.7 million tons of CO2e, which is equivalent to 10.6% reduction from business as usual in 2015.


The efforts of the UAE and Dubai to spearhead clean energy development in the region contribute greatly beyond the borders of the UAE. In a rapidly changing world, Dubai has seized the opportunity to follow a sustainable development pathway as it continues to grow. The clear and supportive vision of its leadership paved the way to develop a long-term strategy and deliver phased, but steadily implemented progress to achieve the goals of its DIES 2030. The strategy has resulted in investment certainty for the private sector and in several successful PPPs that resulted in low-cost solar energy, with positive ramifications for the future of solar not only in Dubai but the entire region.

The Emirate’s model as illustrated in Figure 3 is becoming a benchmark for the transition to a clean energy future in a region historically perceived as a synonym for “oil”. By 2030, Dubai expects to turn its sunny days into a sustainable fuel for generations to come and deliver strategic programs to support its Green Agenda to become a role model in energy management and sustainability in the region.

FIGURE 3. Dubai’s Sustainable Energy Model.


  1. Government of Dubai. (2016). Dubai Plan 2021,
  2. Dubai Supreme Council of Energy. (2016). Our members,
  3. Emirates 24/7. (2006, 6 February). 50% of Dubai Taxi fleet hybrid by 2021,


The content in Cornerstone does not necessarily reflect the views of the World Coal Association or its members.
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The Role of Fracking in the U.S. Utility: Battle of Gas vs. Coal

By Jill Tietjen
President and CEO, Technically Speaking, Inc.
Russell Schussler
Vice President, System Planning,
Georgia Transmission Corporation

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


Historically, the dominance of coal-fired power generation was enabled by two factors: (1) the increasing efficiency of power plants over time and (2) the abundance of local coal supply. Generating units were no larger than 150 MW from the 1930s through to the mid-1950s. By 1975, however, due to technological advances, 1300-MW generating units were developed and installed —increasing in generating capacity magnitude by almost a factor of 10 as well as significantly improving energy efficiency.1 The costs of electricity production declined as each new generating unit was installed. With coal basins located throughout the continental U.S. and Alaska, coal was easily accessible, available, economically priced, and readily stockpiled.2

A coal-fired power plant.

The Middle East oil embargo in the early 1970s, ensuing economic conditions including rampant inflation, the Powerplant and Industrial Fuel Use Act of 1978, and the accident at the Three Mile Island nuclear plant in 1979 meant that the installation of new electric generating facilities no longer led to decreases in electric rates. In addition, electric consumption stopped growing at a dependable annual rate of 7%. These events in the 1970s laid the foundation for the changes in electric generation mixes that are now observed in the 21st century.

According to data from the Energy Information Administration (EIA) of the U.S. Department of Energy (DOE), coal provided about 47% of the total electricity generated (see Figure 1) in 1949. Coal reached its peak level of power production in 1988, providing almost 57% of all electricity produced. In 1949, power that was not produced using coal as a fuel source was primarily generated by conventional hydroelectric power, petroleum and its derivatives, and natural gas. Nuclear power made its debut for electric power generation in 1957. Other sources—including wood, waste, geothermal, solar/photovoltaics (PV), and wind—generated electricity at significantly lower levels than coal, natural gas, or nuclear.3

FIGURE 1. Historical net electricity generation (electric power sector only), 1949–2015.


During the 19th century, coal was the major fuel that enabled the U.S. to evolve from an agricultural society to a world economic power. In the early 20th century, coal was used primarily as a raw material to power the nation’s industrial and transportation sectors and for home heating, although Thomas Edison used coal to fire the first electric power generation station in 1882 in New York City.4

The major expansion of the U.S. electric utility systems occurred from the 1960s through the 1980s. During that time, coal was the primary fuel for baseload generation and coal production nearly doubled from 1970 to 1990.4 For a long period, larger, more efficient coal additions were aligned with efforts to improve both the economy and the environment. Coal as a fuel for electricity generation remains plentiful. The EIA estimates that, at the 2014 consumption rate of about one billion tons, known coal reserves in the U.S. will last for more than 250 years.5

T. A. Smith Natural Gas Station. (Courtesy of Oglethorpe Power Corporation)


As demand for electricity grew throughout the late 1900s, natural gas was not the preferred fuel choice for several reasons. The 1978 Powerplant and Industrial Fuel Use Act (FUA) prohibited the use of natural gas and oil as the primary fuel in electric utility power plants or large industrial boilers. Although these restrictions were eliminated with the repeal of the FUA in 1987,6 the price level of natural gas, restrictions on its availability during the winter season, and its significant price volatility precluded its use for baseload generation.

The first public use of natural gas for electric power generation occurred in 1939/1940 in Switzerland. The first natural gas combined-cycle unit began operating in 1961 in Austria.7 Advances in materials and technology included the development of aeroderivative gas turbines that significantly improved operational efficiency versus previous gas turbine models.8 Aeroderivative gas turbines are compact, using lighter weight designs (originally developed for aviation use); with high efficiency and fast-start capabilities, they are well suited for power generation.9 Pairing these turbines with heat recovery steam generators led to today’s natural gas combined-cycle units, some of which offer among the highest efficiencies of any fossil-fuel-sourced generation.


Increasingly, public and regulatory attention has focused on the environmental impacts of coal-fired generation and coal mining in the years since the passage of the Clean Air Act in 1970 and its later amendments. In fact, some in the U.S. point to a “war on coal”.10 Owners of coal-fired generation have retrofitted or retired power production facilities as a result of actions taken by the U.S. Environmental Protection Agency (EPA). In addition, the global focus on climate change and concomitant efforts to reduce coal-fired power plant emissions have resulted in all decisions concerning coal-based electric generation receiving significant scrutiny.

The regulations issued by, or actions of, the EPA affecting ozone, sulfur dioxide (SO2), nitrogen oxides (NOx), particulate matter (PM), ash disposal, water, mercury, and carbon dioxide (CO2) emissions have impacted the cost competitiveness of coal-fired units more than natural gas-fired units, as emissions from natural gas are significantly lower than from coal. Many coal-fired generating units were retrofitted to comply with these regulations and experienced associated increases in capital, operating, and maintenance costs, while the additional cost requirements pushed other units into retirement. The Clean Power Plan (CPP), currently being adjudicated, would further reduce coal’s competitiveness and accelerate the retirement of additional coal facilities.


The advent of fracking significantly increased the amount of economically recoverable natural gas and oil. Very similarly to coal basins, shale deposits are widespread in the U.S. with significant formations now etched into the public’s mind in North Dakota (Bakken), Pennsylvania (Marcellus), and Texas (Barnett and Eagle Ford).11

The Marcellus Shale and Bakken Formation became producers of oil and natural gas through the advancement of fracking. As a result, domestic crude oil and natural gas production has increased significantly in the U.S. in the last decade, as shown in Figure 2. In conjunction with that increase, the price of natural gas has also decreased to a level that makes it competitive with coal for baseload generation.12

FIGURE 2. U.S. dry shale gas production.

This increase in production and domestic availability has also reduced the volatility historically associated with natural gas prices. Of geopolitical importance, the U.S. is now an exporter of oil, can produce enough natural gas for energy independence, and is exporting liquefied natural gas.13,14


Much current rhetoric touts that renewable energy (generally referring to solar and wind but ignoring hydroelectric power) will become the primary energy source for electricity in the near future. However, electric professionals as well as the U.S. federal government forecast that nuclear, coal, and natural gas resources will be required to provide a reliable electricity grid for the foreseeable future.15 These are so-called “dense” energy sources and the spinning turbines associated with these generation technologies provide the inertia that the power system needs to be stable, especially as renewable resources become a larger percentage of the generation mix. A, 16

The EIA’s 2016 Annual Energy Outlook forecasts that coal will provide 21% of total electricity in 2030 and 18% in 2040, with total coal production of approximately 640 million tons in 2040 (see Figure 3).15 In the face of slowing growth in electricity use (less than 1% per year), natural gas is projected to provide 38% of the total electricity produced in 2040, while nuclear will provide about 16%.15,17

FIGURE 3. Electricity net generation.


Projections for the future need to be made with humility and interpreted with caution. In the not-too-distant past (the 1970s), there was a belief that the world was entering a new Ice Age.18 Around that same time, it became illegal to build electric power generation fueled primarily with natural gas or oil. Also in that era, solar and wind technologies were in development but much too expensive for either utility-scale or individual consumer application. In the 1990s, it was accepted that the “gas bubble” would break and that natural gas, besides being unable to support baseload generation, would become too costly to power intermediate generation.19 There were serious concerns that natural gas combined-cycle plants would become far too expensive to operate. Justifications for natural gas combined-cycle plants were supported by backup plans showing that they could be converted and powered by gasified coal when natural gas became too costly.

Fracking site.

Today, concerns about global climate change have led to calls for the reduction of emissions from fossil fuels, including coal. The results of the earthquake and tsunami affecting the Fukushima Daiichi nuclear power plant in Japan have led to projected and actual changes in the use of nuclear power around the world. Utility planners have learned that their crystal balls can be quite cloudy. The forecast is always wrong—the only issues are in which direction and by how much—and these factors only become obvious in retrospect. Planning for future generation sources thus requires flexibility that reflects mindfulness of the abrupt changes that can take place underlying pricing and availability of any fuel source.20 Good planning results in solutions robust enough to adjust to the differences between forecasts and reality.

As the 21st century unfolds, the roles of natural gas and coal may well take unforeseen twists due to developments in areas such as clean coal technology or environmental regulations impacting natural gas, nuclear power, or renewable technologies. Lastly, it should be noted that this article has focused on U.S. generation. The availability and infrastructure for natural gas generation is lacking in many other parts of the world, particularly some developing countries. Under current conditions worldwide, coal-based generation in many cases will be the superior option considering developmental needs, economics, and the environment.20,21


Although coal-fired generation dominated the electricity market for many decades, the advent of fracking has led to an abundant domestic natural gas supply with low and stable prices that are competitive with coal prices. With the technological advances in gas turbines and combined-cycle units, natural gas-fired generation has become economically competitive with coal and produces lower emissions. Increasing regulations associated with clean air, clean water, and global climate change are also increasing the costs to build, operate and maintain, and fuel coal-fired generation. Nevertheless, both electric utility professionals and the U.S. federal government project that, by 2040, coal will still be providing about 20% of the total electricity requirement in the U.S. That level of generation will require the mining of over 600 million tons of coal. Although natural gas will replace coal as the dominant fuel, coal and nuclear power will still be required to supplement the baseload demand requirements of customers throughout the U.S. With demand for electricity increasing in other countries around the world, many of which may not have the infrastructure to support natural gas generation, coal-based generation may still be required globally due to the economic and environmental needs of the developing world.


  • A. The denser the energy resource the more energy that can be produced in a smaller space. Example power densities include: wind – 1 watt per square meter; solar – 6 watts per square meter; natural gas – 28 watts per square meter; nuclear power – 50 watts per square meter.16


  1. Cassaza, J.A. (1993). The development of electric power transmission. IEEE Case Histories of Achievement in Science and Technology. New York: IEEE.
  2. U.S. Energy Information Administration (EIA). (2016, 24 March). U.S. coal reserves,
  3. EIA. (2016, 26 August). Monthly energy review (DOE/EIA-0035). Table 7.2, Electricity net generation,
  4. U.S. Department of Energy National Energy Technology Laboratory. (n.d). Key Issues & Mandates: Secure & Reliable Energy Supplies—History of U.S. coal use,
  5. EIA. (2016, 17 June). Coal explained: How much coal is left,
  6. EIA. (n.d.). Repeal of the Powerplant and Industrial Fuel Use Act (1987),
  7. Miser, T. (2015, 13 February). A short history of the evolving uses of natural gas, Power Engineering, 119(2),
  8. Hunt, R.J. (2011). The history of the industrial gas turbine (Part I The first fifty years 1940–1990). Publication 582, The Independent Technical Forum for Power Generation. Morpeth, UK: The Institution of Diesel and Gas Turbine Engineers,
  9. Siemens. (n.d.). Siemens gas turbines,
  10. Utech, D., & Patel, R. (2015, 3 August). The Clean Power Plan: Myths and facts [The White House Blog],
  11. Shooters: A “fracking” history. (n.d.). American Oil & Gas Historical Society,
  12. EIA. (2016, 20 July). Energy in Brief: Shale in the United States,
  13. Egan, M. (2016, 29 January). After 40-year ban, U.S. starts exporting crude oil. CNN Money,
  14. Domm, P. (2016, 25 February). U.S. exports of LNG mark a turning point in the market. CNBC,
  15. EIA. (2016, 17 May). Annual energy outlook 2016 early release: Annotated summary of two cases,
  16. Bryce, R. (2014). Smaller faster lighter denser cheaper. New York: Public Affairs.
  17. EIA. (2012, 27 September). Annual energy review 2011. Table 8.2a, Total electricity net generation: Total (all sectors), 1949–2011,
  18. (2103, 21 May). The 1970s Ice Age scare,
  19. Costello, K., Huntington, H.G., & Wilson, J.F. (2005). After the natural gas bubble: An economic evaluation of the recent U.S. National Petroleum Council Study. The Energy Journal, 26(2), 89–110.
  20. Eaves, J. (2012, May). The new Arch Coal,
  21. Mann, T. (2016, 18 August). General Electric gets bullish on coal – again. The Wall Street Journal, B1–B2.

The authors can be reached at or


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

By Jon Gibbins
Director, UK CCS Research Centre
Professor of Power Plant Engineering, University of Sheffield
Hannah Chalmers
Deputy Director (Network), UK CCS Research Centre
Senior Lecturer in Mechanical Engineering,
University of Edinburgh


At the Paris climate summit in December 2015, world leaders agreed to work to limit global climate change to 2°C and to try to achieve 1.5°C. To put the necessary cap on total cumulative greenhouse gas (GHG) emissions, leaders also agreed on net-zero emissions; that is, there must be “a balance between anthropogenic emissions by sources and removals by sinks of greenhouse gases in the second half of this century”.1

Net-zero emissions will require carbon capture and storage (CCS) for all fossil fuels and other technologies (e.g., biomass with CCS or direct air capture) for residual emissions from fossil fuel extraction and from other anthropogenic sources such as agriculture. This is radically different from the current position wherein CCS has been mainly identified with coal use and considered unnecessary for other fossil fuels. Coal-fired power generation with partial CCS is competing with unabated natural gas power plants—an impossible challenge economically unless gas and oil prices are very high. If, however, coal with CCS has to compete with gas with CCS then the situation is more balanced, particularly in markets such as China where the capital costs for coal power plants and coal prices are relatively low compared to natural gas.


Following earlier CCS initiatives such as the Sleipner injection project,2 the IEA GHG program,3 the Greenhouse Gas Technology conferences,4 the planning for CCS as part of the Gorgon LNG mega-project,5 and early SaskPower planning for coal CCS projects,6 CCS gained international prominence in the mid-2000s. Key events included the inaugural 2003 meeting of the Carbon Sequestration Leadership Forum (CSLF7) in the U.S., the 2005 Gleneagles Conference in Scotland,8 and the launch of the Global Carbon Capture and Storage Institute (GCCSI)9 in 2009.

Subsequently, plans for CCS deployment expanded rapidly, driven by increasing demand and high natural gas and oil prices prior to the 2009 recession (see Figure 1) and continuing
beyond 2009 because of commitments and established positions and, in the U.S., because of support for CCS in the so-called Stimulus Package (American Recovery and Reinvestment Act of 2009).

FIGURE 1. Historic and future North American natural gas market prices.10,11

New CCS projects were expected to be placed on coal power plants, with major coal-build programs anticipated in the U.K., Europe, U.S., and Canada. Strong environmental protests were a driver for CCS on many of these proposed new coal-fired power plants. There was also an expectation that coal+CCS+EOR (enhanced oil recovery) would be competitive with natural gas with no CCS12 (e.g., SaskPower’s BD3 plant in Canada and the Petra Nova Project in Texas). However, the collapse of high natural gas and oil prices due to the recession resulted in a rethink of “peak oil”, and hence lower CO2 sales prices for EOR, and also of the need for a “dash for coal”.


The current CCS position follows on from the changes after the recession and also from shale gas developments in North America. Minimal numbers of new coal plants have been built in CCS-championing countries (e.g., U.S., UK, Australia, Canada, and the Netherlands) with limited prospects for future construction. Electricity demand reduction is a partial reason for this in some markets (e.g., the UK) as is the growing output from intermittent, subsidized renewable generation sources. The Waxman-Markey climate legislation in the U.S., which contained incentives for CCS, failed to pass in the Senate in 2009,13 meaning coal+CCS+EOR in North America cannot compete with unabated natural gas, even with government capital support (such as from the U.S. stimulus incentives).

Without countries that champion CCS deploying it at scale, neither other developed economies (e.g., Germany, Poland) nor developing economies (e.g., China, India) are under much pressure to deploy CCS, even for coal—especially when there is no economic incentive or immediate global GHG emission reduction imperative to drive it.


Alternative applications for CCS other than coal power exist and are recognized as vital in the long term by CCS-championing countries. However, there is currently no immediate GHG constraint nor public opinion driver to make CCS as imperative as it was for coal pre-recession. Globally important applications for meeting net-zero targets include:

  • Energy-intensive industries: usually grouped together, but in practice a heterogeneous range of applications (in terms of technology, scale, cost, location, etc.) and are almost always exposed to global competition. Therefore, production costs cannot be raised unilaterally by a country without import controls.
  • Natural gas CCS: limited new natural gas plants in many places, with construction under pressure from intermittent renewables; reluctance by some stakeholders to get CCS associated with natural gas power because it may then become effectively impossible to build; also U.S. Department of Energy (DOE) CCS funding is specifically for coal.
  • Biomass and waste combustion: of interest for negative emissions, but no developed proposals to incentivize negative emissions have been made anywhere yet.
  • Hydrogen: being discussed for heat in buildings, industry, and also, with interim storage, for electricity production in markets where (subsidized) zero-dispatch-cost renewables make CCS plant load factors uncertain.


The idea that CCS should be supported in ways analogous to renewables appears to be gaining traction in some countries, such as the UK (Feed in Tariffs with a Contract for Difference for electricity14) and the U.S., but has received little attention elsewhere.

There are also some suggestions in the U.S. and UK that coal should be supported for political reasons, but coal+CCS would inevitably be more expensive than unabated gas. Coal+CCS versus natural gas+CCS would be more favorable to coal, but coal probably would still be more costly (particularly with large amounts of renewables in the system and hence uncertain load factors). The uncertainty in the timing and quantity for new nuclear power plants also makes the scope for CCS deployment and the strategic value of coal uncertain in the U.S. and UK.

CCS is therefore currently in a regrouping phase. Old plans either have almost all been completed or are defunct. New major projects and concepts for CCS are still nascent. This does not mean, however, that the CCS field should be inactive, rather the reverse. Major new projects take around a decade to develop and so work on them needs to be urgently advanced. The time available while this happens is a priceless resource that can be used to reduce costs and risks for the next tranche of major projects, as described below.

Making CCS Readiness More Widespread

The idea of building new fossil fuel infrastructure to be CCS ready is becoming more accepted in both developed and developing countries. Examples include the UK’s capture-ready guidelines used for power plant permitting15 and the Guangdong “CCS Ready Province” initiative16 in China. However, anecdotal evidence suggests that in some cases, where it is not a legal requirement, the fact that new facilities have been designed and located so as to be capture ready is deliberately not stated to avoid pressure to undertake CCS before competitors.

Establishing Proven CO2 Transport and Storage Infrastructure Options

Storage sites need to be further de-risked for prospective storage applications, with potentially significant costs, especially for offshore storage. Measures to make new plants CCS ready require some thought to be suitable for specific infrastructure and also to adapt to changes as CCS technology develops. Defining future shared pipeline routes (or CO2 shipping options) would benefit CCS readiness plans greatly in some places.

Fast-track Small-Scale Projects

Successful small-scale projects (including on coal) could help to raise the profile of CCS and to partially rebuild industry confidence, and also could be used (in conjunction with other activities; see below) as part of a program of cost and risk reduction for future projects. Small-scale, modular CCS units could also have direct applications in some markets, not least for flexibility to cope with intermittent renewable outputs.

Raising Commercial Readiness of Post-combustion Capture

It seems unlikely that many (any?) new technology concepts will be brought to commercial readiness by the next stage of CCS deployment since this would require major speculative, funding for a reference plant. NET Power’s Allam Cycle17 is a possible exception. Recent large gasification-based pre-combustion capture trial plants (e.g., the Kemper plant in Mississippi18) have not gone well. Post-combustion capture (PCC) projects, SaskPower19 and Petra Nova20, are going largely as planned. When the next large-scale CCS projects are built, PCC may be the only commercially proven choice available for coal and gas power, and quite possibly the most competitive. PCC is also the only capture technology with full-scale experience available that can be used, with design studies and pilot-scale testing (see Figure 2), to produce improved second-generation PCC technologies for the next stage of CCS deployment.

FIGURE 2. Post-combustion test unit at the UK Carbon Capture and Storage Research Centre’s Pilot-scale Advanced Capture Facility (UKCCSRC PACT).21

Developing CCS Policy, Regulations, Incentives, and Business Models

Ways to meet the cost of CCS need to be in place, as well as the organizations (private, possibly regulated, and/or public) with the necessary expertise and financial resources to undertake projects. National and international laws and regulations need to allow CCS. For example, the London Protocol amendments to allow cross-boundary transfer of CO2 for sub-seabed storage are not yet ratified.22 CCS treatment in GHG accounting may still have issues. Possible liability for stored CO2 is a potential show-stopper for private companies.

Acceptance of CCS as a Means of Delivering Clean Electricity Targets

Low-carbon electricity from fossil-fired power plants with CCS needs to be given equal treatment with nuclear and renewables in new policies to meet the Paris Agreement objectives. An example of this is the recent “Three Amigos” initiative by the U.S., Canada, and Mexico that includes producing 50% of electricity from clean sources. The calculation for the fraction of CCS plant output counted as zero carbon output needs to be rigorous environmentally, but it is essential that it is based on actual plant performance to encourage innovation in plant design and operation and to take advantage of the inherent flexibility of CCS for reducing costs.

CCS Uses in Energy-Intensive Industries

The cement, iron and steel, and chemicals industries are all major users of coal and other fossil fuels and are large GHG emitters in many countries. Effective utilization of the time between now and the beginning of the more widespread, commercially driven deployment of large-scale CCS facilities can be based on fast-tracked small-scale work as well as larger industrial projects where CO2 storage or EOR markets are already available (e.g., the Decatur Project,23 Shell Canada’s Quest Project,24 Air Products’ Port Arthur project25).


One important challenge in establishing and rolling out CCS as a global option for reducing CO2 emissions is ensuring sufficient numbers of trained people are available at all stages of the project life cycle. Particularly for early projects, it is likely that most contributors to project design and delivery (and supporting policy and regulation) will be applying skills normally used for other applications.

A range of initiatives are underway to develop and support a cohort of CCS professionals. For example, most universities with CCS research interests include course material on CCS in their undergraduate and MSc programs. Several MSc programs are dedicated to CCS and PhD-level programs with significant CCS content are also available. Some graduates from such programs are developing careers in CCS R&D and consultancy, while others are using the skills developed during their studies in other energy-related roles.

It is important to ensure that individuals who are early in their career are able to gain as much practical experience as possible and also to learn from more experienced practitioners who may retire before widespread deployment of CCS. In this context, “learning by doing” at pilot-scale facilities (see Figure 3) and through targeted international collaboration is particularly important in the next decade as part of a broader effort to ensure that necessary expertise is grown to facilitate effective global rollout of CCS in the longer term.

FIGURE 3. Early-career researchers and CCS specialists at the CCPilot100+ final meeting.26 Six complementary R&D projects and 23 four-week secondments were provided to research students on the CCPilot100+ pilot post-combustion capture unit27 at Ferrybridge Power Station in West Yorkshire, England.

CCS projects are operating in many countries, but prospective workers and researchers should look at a variety of scales and different fuels and applications. The range of disciplines required is growing, with specialists in areas other than CCS becoming more important as technologies are deployed at pilot scale or larger in “real” applications, and a range of new issues are discovered and addressed. Strong cooperation between industry and researchers is also needed for cost reduction. It may appear that there are not many job opportunities now, but CCS worker numbers will have to grow rapidly if net-zero emissions are to be achieved. With exponential growth in CCS deployment during the next two or three decades, experienced workers in all aspects of CCS development, design, and construction will be in short supply. Once a significant number of CCS installations are in place a large workforce of operators will be required. Experience with power plants and other long-lived major infrastructure investments also suggests that in-service modifications, improvements, and maintenance will be a continuous and major business.

The drive to achieve net-zero emissions from all fossil fuel use within perhaps 50 years or less will be a challenging but vital job for the current generation, and many future generations, of CCS workers and researchers.


  1. United Nations Framework Convention on Climate Change. (2015). The Paris Agreement,
  2. Statoil. (2010). Annual Report 2010 – Our CCS projects,,Safety,ClimateAndTheEnvironment/Climate/CarbonCaptureAndStorage/Pages/OurCCSProjects.aspx
  3. IEAGHG. (2016). The IEA Greenhouse Gas R&D Programme,
  4. IEAGHG. (2016). The Greenhouse Gas Control Technologies (GHGT) conference series,
  5. Chevron Australia. (2016). Gorgon Project,
  6. Stobbs, B. (2007, 31 May). The clean coal advantage. Presented at Expert Meeting on Financing CCS Projects, London, England,
  7. Carbon Sequestration Leadership Forum. (2016). A global response to the challenge of climate change,
  8. G7 Information Centre. (2005). Official documents: Gleneagles Summit. July 6–8, 2005,
  9. Global CCS Institute. (2016).
  10., Inc. (2016). Commodity futures price quotes for natural gas (NYMEX),
  11. U.S. Energy Information Administration. (2016). Henry Hub natural gas spot price,
  12. Marsh, G. (2003, May). Carbon dioxide capture and storage— A win-win option? AEA Technology, Harwell, Report ED 01806012,
  13. Reilly, A., & Bogardus, K. (2016, 27 June). Seven years later, failed Waxman-Markey bill still makes waves. E&E Daily,
  14. UK Department for Business, Energy & Industrial Strategy. (2015, 26 February). Electricity market reform: Contracts for difference,
  15. UK Department of Energy and Climate Change. (2009, November). Carbon capture readiness (CCR): A guidance note for Section 36 Electricity Act 1989 consent applications. Document URN 09D/810,
  16. Capture Ready. (2016). CCS Information Team,
  17. NET Power. (2016). A new power system that generates lower-cost electricity from fossil fuels than current power systems while producing zero air emissions,
  18. The Kemper Project. (2016). The Kemper Power Plant,
  19. SaskPower. (2016). SaskPower CCS: The world’s first post-combustion coal-fired CCS facility,
  20. NRG. (2016). Petra Nova – WA Parish Generating Station,
  21. PACT. (2016). The UKCCSRC Pilot-scale Advanced Capture Technology (PACT) facilities,
  22. Dixon, T., & Kleverlaan, E. (2015, 1 May). Update on London Protocol developments on transboundary CCS and on geoengineering. 14th Annual CCUS Conference, Pittsburgh, PA,
  23. U.D. Department of Energy National Energy Technology Laboratory. (2015, November). Midwest Geological Sequestration Consortium—Development Phase Illinois Basin – Decatur Project Site. Report NT42588,
  24. Shell Canada. (2016). Quest carbon capture and storage project,
  25. US Department of Energy Office of Fossil Energy. (2016, 30 June). Texas CO2 capture demonstration project hits three million metric ton milestone,
  26. UK Carbon Capture and Storage Research Centre. (2014). CCPilot100+ University Engagement Programme: Lessons learned,
  27. Dixon, T., Yamaji, K., Carey, J., Damen, K., Fitzgerald, F., & Gardiner, R. (2013). CCPilot100+ operating experience and test results. Energy Procedia, 37, 6170–6178.

The authors can be reached at or


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Coal and Clean Coal Technologies in Turkey

By Mücella Ersoy
Chief Mining Engineer, Turkish Coal Enterprises (TKI)

Coal is Turkey’s most important domestic energy resource. Although the country has large reserves of low-grade lignite and some hard coal resources, its oil and natural gas resources are quite limited. In recent decades Turkey has relied less and less on its domestic resources, leading to concerns about the country’s energy security.

Turkey also has one of the fastest growing economies in the world due to a growing population and increasing industrialization. This has led to expanding energy demand, which increased by nearly a factor of six between 1970 and 2014.A,1,2 In 1970, the share of domestic resources in Turkey’s energy consumption was 77%. The high energy consumption rate, delays in realization of investments for domestic resources, and increasing imports of energy resources resulted in a reduction of 25% in the domestic share by 2014 (see Figure 1).

FIGURE 1. Domestic coal share in total primary energy supply (1970–2014)

Coal’s share, including lignite, in Turkey’s total primary energy supply (TPES) decreased from 24% in 1970 to 13% in 2014. Since 1986, coal has accounted for more than 50% of domestic energy production (see Figure 1). In 2014, the TPES by fuel share (123,937 ktoe) was coal 29.1% (hard coal 16.3%, lignite 12.3%, asphaltite 0.3%, coke 0.2%), other solid fuels 4.9%, oil 26.2%, natural gas 32.4%, hydro 2.8%, geothermal 2.8%, wind 0.6%, solar 0.6%, biofuel 0.1%, and electricity 0.4%.

Turkey has one of the fastest growing economies in the world.

Several recent energy strategy papers published in Turkey have focused on policies to reduce energy import dependency.3–5 A common theme among the papers is the importance of prioritizing the use of domestic resources, particularly lignite, for electricity generation. Several objectives were set that aim to reduce energy import dependency, including:

  • Increasing domestic coal exploration
  • Accelerating the installation of power plants using domestic lignite and clean coal technologies
  • Maintaining the momentum of R&D on coal (particularly on coal gasification and liquid fuel production technologies)
  • Improving investment incentives for coal-fired power plants
  • Retrofitting existing coal-fired power plants


Hard coal reserves are concentrated in the Zonguldak Region on the western Black Sea with lignite reserves scattered throughout the country. Hard coal reserves were estimated at 1.3 Bt. As a result of increased exploration, lignite reserve estimates were increased from 8.3 Bt in 2005 to 15.7 Bt in 2015.B The largest lignite deposits are in Afsin-Elbistan, Konya-Karapinar, Eskisehir-Alpu, Afyon-Dinar, Manisa–Soma, Ankara-Cayirhan, and Kütahya-Tunçbilek, covering the Anatolian plateau from west to east (see Figure 2).

FIGURE 2. Coal basins and fields in Turkey6

Lignite gained prominence as a domestic energy resource in Turkey after the oil crisis in the 1970s. Lignite production increased from 14.5 Mt in 1980 to 42 Mt in 1986, principally to meet the demand of lignite-fired power plants installed during this period. Production reached a peak of 76.2 Mt in 2008 and then decreased. In 2014, 62.6 million tons of lignite were produced, which ranks Turkey as the fifth largest lignite producer country in the world.7 According to the Turkish Statistical Institute, lignite production decreased to 42 Mt tons in 2015.C,8 The decrease can be attributed to the closure of mines due to accidents and increasing operating costs. Hard coal production decreased from 4.6 Mt in 1970 to 2.2 Mt in 1995 and remains relatively unchanged with an annual production of around 2 Mt (see Figure 3).

FIGURE 3. Coal production and imports in Turkey (1970–2014)

In order for Turkey to meet domestic energy demand, it has been importing hard coal since the 1980s (30 Mt in 2014), mostly from Russia, Columbia, the U.S., South Africa, and Australia (see Figure 3). Hard coal is used for electricity generation, steelmaking, cement production, and heating, while lignite is mainly used for electricity generation and, on a minor scale, for heating and industrial purposes.

Reliance on imported coal has increased to meet the demands of new coal-fired power plants. Total coal consumption in 2014 was 97.2 Mt, of which 31.5 Mt was hard coal, 64.7 Mt lignite, 0.771 Mt asphaltite, and 0.347 Mt coke.


Table 1 shows the current operating status of coal-fired power plants in Turkey. In July 2016, 64 units in total (only those having generation capacity >100 MW are counted) were operating, 10 of which (3115 MW) belong to the state-owned electricity generation company, EUAS.

TABLE 1. Coal-fired power plants in Turkey ( >100 MW, end of July 2016)a
Notes. a Total coal-fired installed capacity bESP: electrostatic smoke precipitator. cFGD: flue gas desulfurization. dData for public and privatized domestic coal-fired power plants are from EUAS. Other data are from M. Basaran.9 ePC: pulverized combustion; fCFB: circulating fluidized bed.

As a part of creating a competitive energy market in Turkey, the privatization of power plants has been ongoing for several decades. Since 2013, 24 units of EUAS-owned coal-fired power plants (totaling 4302 MW) have been privatized.

In 2015, coal, including lignite and asphaltite, generated 28.5% of Turkey’s electricity (259.7 GWh). The share of lignite in electricity generation peaked at 47% in 1986. Domestic lignite demand for electricity generation has decreased due to an increase in the number of power stations relying on imported natural gas. However, between 2004 and 2009, lignite’s share of electricity increased to 20.1%, by commissioning of new domestic lignite-fired power stations at Can (2 x 160 MW) in 2003 and Elbistan B (4 x 360 MW) in 2009. Several domestic lignite-fired power plants are also currently under construction. From 2009 to the end of 2015, no additional power plants were commissioned and, as a result, power from lignite decreased to 12%.10 However, this may change with Tufanbeyli (3 x 150 MW), Bolu-Göynük (2 x 135 MW), and Yunus Emre (1 x 145 MW) starting operation at the end of 2015 and in 2016 (see Figures 4 and 5).

FIGURE 4. Installed capacity by fuel type in MW (July 2016, total installed capacity ˜77,000 MW)

FIGURE 5. Domestic and imported coal share in electricity generation in Turkey (1970–2015)

The use of imported coal for coal-fired power plants since 2004 has increased in order to meet power demand in Turkey. Due to the low prices of imported coal in comparison to natural gas, imported coal-fired power plant investments in Turkey are attractive for investors. The use of imported coal reached almost an equal share with lignite in 2013 and a higher share (15%) than lignite in 2015.


Clean coal technologies have been developed and deployed globally to reduce the environmental impact of coal utilization over the past 30 to 40 years. Initially, the focus was to reduce emissions of particulates, SO2, NOx, and mercury. Focus has now moved to the development and operation of low and near-zero GHG emission technologies, such as CO2 capture and storage (CCS).11

Key Drivers for Clean Coal Technologies in Turkey

The key drivers for clean coal technologies in Turkey include:

  • Increasing the use of existing domestic coal resources for energy security
  • Developing domestic coal technologies to reduce high-technology import dependency
  • Competing with imported energy resources, such as natural gas
  • Efficient use of low-quality coal to protect the environment and combat climate change

Climate Change Policy Measures

Turkey is a party to the UN Framework Convention on Climate Change and a signatory to the Kyoto Protocol and Paris Agreement. It submitted its Intended Nationally Determined Contribution (INDC) within the context of the Paris Agreement with an aim to reduce emissions by 21% from the current business-as-usual level by 2030.

Harmonization of Turkish legislation with EU legislation in the coal sector is also underway. In 2010, the EU Directive on Large Combustion Plants (LCPD) was harmonized, under which emission limits for both new and existing plants were established and put into effect in Turkey. A twinning project was also initiated to harmonize Turkey’s policies with those of the EU Industrial Emission Directive (2010/75/EU). Accordingly, LCPD emission limits were included in the Turkish Industrial Pollution Prevention and Control Directive (IPPC) at the end of 2014 and the LCPD was repealed. New coal-fired power plants must now comply with the commitments of the amended IPPC directive. By the end of 2019 existing public and privatized old subcritical coal power plants must also comply. Therefore there is a need for investment to retrofit them to comply with the new emission limits.

Efficiency Improvements for New Coal-Based Power Plants

Turkish policies support efficiency improvements for new domestic lignite coal use. Circulating fluidized beds (CFBs) are preferred for lignite and asphaltite power plants, as they are more readily able to comply with the emission limits of the amended IPPC directive. Efficiency improvements have several benefits:12

  • Prolonging the life of coal reserves and resources by reducing consumption
  • Reducing emissions of CO2 and conventional emissions (1% efficiency improvement provides 2.5% CO2 emission reduction)
  • Increasing a plant’s power output
  • Potentially reducing operating costs

Currently, 49 pulverized coal including lignite power plants are operating. A total of 41 units, or 9.5 GW, are subcritical and were installed prior to the LCPD Directive (2010). The remaining eight units (4.7 GW) use supercritical steam conditions with thermal efficiencies of 41–42%, and are already meeting emission limits.

Image of new built Bolu-Göynük (2 x 135 MW) lignite-fired power plant (Courtesy of Caner Sürmeli, Göynük Control Management, TKI)

Emission Control Technologies

The 1986 air quality directive established emission limits for SO2, NOx, and particulate matter (PM). As a result, new power plants were built with flue gas desulfurization (FGD). In addition, some older plants were retrofitted with FGD. Prior to 2010, NOx emission limits were met through the use of tangential burners in lignite-fired power plants.13 More stringent limits have resulted in the use of de-NOx technologies in new plants. Electrostatic smoke precipitators (ESP) are also used for mitigating PM emissions in all coal-fired power plants in Turkey (see Table 1).

250-kg/hr entrained bed gasifier

Coal Upgrading

Coal upgrading includes coal washing, drying, and briquetting.11 In the last decade Turkey has increased its coal-washing capacity. State-owned coal-producing companies—TKI, EUAS, and Turkish Hard Coal Enterprises (TTK)—and their contractors have a total coal-washing capacity of 5780 tonnes/hr. A pilot-scale coal drying and enhancement (CDE) system was successfully designed, built, and tested at Afsin-Elbistan Power Plant. Tests have shown that the moisture in lignite has been reduced by 10% point and calorific value has been increased by 30%.14

Lignite Gasification Projects

Integrated gasification combined-cycle (IGCC) is a promising technology based on its environmental performance, especially regarding the ability to carry out pre-combustion CO2 capture. IGCC plants also have very low SO2, NOx, PM, and mercury emissions. Although most IGCC studies have focused on bituminous coal, lignite has been successfully gasified.15

Turkey is involved in several R&D projects on lignite gasification, focused on investigating low-quality lignite gasification characteristics using different gasifiers. TKI and Hacettepe University in Ankara are part of the EU’s 7th FP project “Optimizing gasification of high-ash coal for electricity generation (OPTIMASH)” in collaboration with India, France, and Netherlands. That project aims to design, install, and test a 1-MWth IGCC plant in India using pressurized CFB technology operating at a pressure of 10 bar. Based on the success of this initial project, Turkey is considering funding a 10-MWth IGCC pilot plant.16

Other gasification projects include a pilot-scale (250 kg/hr) entrained-flow gasifier to produce methanol and a lab-scale (20 kg/hr) CFB gasifier in TKI’s Tunçbilek Area. A pilot-scale coal and biomass to liquids plant with 1.1-MWth capacity in TKI’s Soma Area and a lab-scale plasma-aided gasification facility are other ongoing projects.


CCS is also being investigated in Turkey. Several lignite gasification R&D projects have a CO2 capture component (e.g., liquid production from a coal and biomass blend project). There is also a project to assess CO2 storage potential in Turkey, as well as a modeling and prefeasibility study for injection of CO2 into an oil field.17,18


Turkish energy policies and strategies are driven by increasing energy demand and dependency on importing energy resources and technologies. Turkey has considerable low-quality lignite reserves. Continuing to use lignite will require clean coal technologies to comply with environmental regulations and climate change commitments.

The future of coal in Turkey will be driven by the domestic use of lignite. The Turkish government aims to continue to use lignite for power generation. This is evident in its commitment to further exploration, investment incentives, improving environmental regulations, and supporting research into more efficient use of lignite. In line with those goals, development and deployment of more efficient coal-fired power plants, and research on gasification and CCS, will continue to be pursued by the country.


The author wishes to thank Dr. İskender Gökalp for his valuable contributions to this article.


  • A. The analysis in the article is based on the energy balance sheets of the Ministry of Energy and Natural Resources (MENR); all electricity generation data are from the Turkish Electricity Transmission Company (TEIAS) unless otherwise stated.
  • B. The reserve classification system used in Turkey is exclusively based on the geological assessment; this means that not all of the reported reserve estimates are economically recoverable quantities.
  • C. Production data for 1970–2014 are from MENR Energy Balance Sheets; 2015 production is taken from the provisional data from Turkish Statistical Institute.


  1. Republic of Turkey Ministry of Energy and Natural Resources (MENR). (n.d.). Yearly energy balance sheets of Turkey (1970–2014),
  2. Gökalp, İ., & Ersoy, M. (2009, October). Turkey sustainable coal techno-economic conditions. Proceedings of 11th Energy Congress, Izmir, Turkey.
  3. MENR. (2009, 21 May). Energy Market and Energy Security Strategy Paper [in Turkish],
  4. Republic of Turkey Ministry of Development. (2014). The Tenth Development Plan (2014–2018),
  5. MENR. (2015). The strategic plans of MENR (2015–2019) [in Turkish],
  6. Şengüler, İ., Kara, İ., Bulut, Y., Yapıcı, E., Karabağ, E., Taka, M., Özdemir, M., & Dümenci, S. (2015). Coal exploration in Turkey: MTA projects and new discovered lignite fields. INERMA-2015, International Energy Raw Materials and Energy Summit, 1–3 October, İstanbul.
  7. International Energy Agency (IEA). (2015). Statistics “coal information,”, Part II, p. II.6.
  8. Turkish Statistical Institute. (2015). Table 1. Solid fuels quantity production, import, export, deliveries, stock exchanges,
  9. Basaran, M. (2013). Coal fired power plants in Turkey. Panel on Coal-Fired Power Plants and Investment Models. METU Alumni Association, 23 February, Ankara, Turkey.
  10. Turkish Electricity Transmission Company (TEIAS). (n.d.). Turkish electricity generation—Transmission statistics [1970–2014], and (2015-2016)
  11. IEA Coal Industry Advisory Board. (2008). Clean coal technologies: Accelerating commercial and policy drivers for deployment,
  12. IEA Coal Industry Advisory Board. (2010). Power generation from coal: Measuring and reporting efficiency performance and CO2 emissions,
  13. ünver, Ö., Tüzüner S., Başaran M., Ersoy, M., Ercan, N., Gürkan, M., & Gürkan, S. (2010). Clean coal technologies [in Turkish]. WEC/Turkish National Committee publication.
  14. Bilirgen, H., Bilirgen, F., & Karadut, M. (2015, May). Field performance tests of an innovative coal drying and enhancement system at Afsin-Elbistan Power Plant. Presented at 21st ICCI 2015, Istanbul, Turkey.
  15. Orhan, E.C., Gulcan, E., Gulsoy, O., Ergun,L., Can,.M., & Ersoy,.M. (2015). Strategies for modelling and simulation aided design of a coal washing plant for gasifier feed preparation. Presentation at 32nd Annual Pittsburgh Coal Conference, 5–8 October, Pittsburgh, U.S.
  16. Gökalp, İ., & Ersoy, M. (2012). OPTIMASH project: A technological option for electricity generation from Turkish lignites. World Energy Council Turkish National Committee, Proceedings of 12th Energy Congress, 14–16 November, Ankara.
  17. Ersoy, M. (2009, 27 October). Overview of CCS situation of Turkey. EU-European Technology Platform for Zero Emission Fossil Fuel Power Plants (ZEP) 16. Government Group Meeting, Brussels.
  18. Okandan, E., Karakece,Y., Cetin, H.,Topkaya, İ., Parlaktuna, M., Akin, S., Bulbul, S., Dalha, C., Anbar, S., Cetinkaya, C., Ermis, I., Yilmaz, M., Ustun, V., Yapan, K., Erten, A.T., Demiralin, Y., & Akalan, E. (2011). Assessment of CO2 storage potential in Turkey, modeling and a prefeasibility study for injection into an oil field. Energy Procedia, 4, 4849–4856.


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India’s Dash for Coal Loses Pace

By Jeremy Bowden
Contributing author, Cornerstone

India has huge potential for growth in energy demand. It hosts one sixth of the world’s population and boasts the third-largest economy in purchasing power parity terms,1 but currently accounts for only 6% of global energy use, while 20% of the population—240 million people—still lack access to electricity.2 The World Bank suggests India’s GDP will grow by 7.9% in 2016, more than twice the global average.3 This growth, combined with modernization, urbanization, and government policies to assist those affected by energy poverty, are all expected to help drive electricity-sector growth, which has averaged 6.34% since 2009.4 (Figure 1 depicts the steady growth in India’s electricity production since 2009.)

FIGURE 1. Growth in electricity production

As a result, the International Energy Agency (IEA) estimates that India will add a quarter to current global energy demand by 2040, overtaking OECD Europe, and nearing consumption levels of the U.S.5 To achieve this, its power sector needs to almost quadruple in size, which will require an estimated US$2.8 trillion of investment by 2040.5 According to the IEA, the use of coal in power generation and industry is expected to rise sharply, increasing demand for coal and making India by far the largest driver of growth in global coal use.5 India is also expanding renewables and nuclear, targeting a 40% share of non-fossil fuel capacity in the power sector by 2030.6

The IEA also expects India to be the world’s largest coal importer by 2020, overtaking Japan, the EU, and China, due to the rapid expansion of its use in the energy and industrial sectors as part of the country’s broader economic policy.4 However, recent events cast some doubt over the IEA predictions. First, imports have been falling for over a year (after having risen sharply, as expected, into early 2015), partly due to higher domestic production and stocks, but also due to lower peak power shortages, low thermal power utilization rates, and, since COP21, perhaps a greater emphasis on renewables.

“India’s import of thermal coal in FY16 will be around 155–160 million tonnes (mnt), compared with around 185 mnt in FY15 because of low imports by power generation companies and increased availability of domestic coal,” said Viresh Oberoi (CEO and MD, mjunction services) in June.7 The imports may decline further, to about 150 mnt in the next fiscal year, with only coastal power plants importing—some of which are only able to run on higher quality imported coal. However, he cautioned that the situation may change if plant load factors increase from the record low of 61.6% reached in FYI15.8

Analysts disagree over whether the dip in imports is temporary. The Global Institute of Energy Economics and Financial Analysis claims imports will soon cease completely: “The country is now firmly on track to meet its publicly-stated goals of ceasing thermal coal imports by 2017-18,” it said in an April article.9 However, a report from the Fitch Group firm BMI Research in January stated that “coal imports will remain strong over the coming quarters as India will continue to be unable to meet domestic coal consumption.”10 It claimed India had a structural deficit of 187 mnt in 2015. “Over the long term, as India attempts to hit its ambitious plans of doubling production by 2020, and production from its auctioned coal mines finally comes online, then we expect imports to fall.”

Second, cutbacks for coal-fired capacity have been announced. India currently has a thermal power capacity of 211 GW, after 20.8 GW was added in 2014 and 2015—the highest on record and well above the target of 17.8 GW. The plan was to add an additional 113 GW of new coal capacity by 2022, most of which is already under construction. In addition, India currently has a further 289 GW of coal capacity in the planning stages. The IEA estimated that this would require around US$1.2 trillion investment by 2040.5 However, the financing available for new capacity is restricted by high network losses—both to illegitimate users and sub-optimal network operation—among India’s local distribution utilities, which reduces revenue.


In April 2016, the Ministry of Power announced it had scaled back its projected thermal power capacity growth forecast by 50 GW, reducing the target from 289 GW to 239 GW by 2022.11 Then in May 2016, the chairman of the Central Electricity Authority announced plans to close up to 37 GW of antiquated subcritical coal plants—equal to 20% of India’s current coal fired power fleet, or 12% of the total system capacity. These units can produce electricity at a relatively low cost and their closure is opposed in some regions where the cost of electricity is a particularly sensitive and politically charged issue.

These moves reflect a change in tone among many national politicians since the COP21 deal was signed in Paris last December. The 2015 statement by Piyush Goyal, Minister of State for Power, Coal and New & Renewable Energy, that “universal and affordable energy access 24/7 … is the mission of this Government under Prime Minister Modi”6 has been replaced by less bullish comments such as this from Mr. Dubey, chairman of the Central Electricity Authority, speaking in May of this year: “Our first concern is emissions … We also want plants to be more efficient in use of resources.”12

The change in emphasis was reinforced in June, when Prime Minister Modi, speaking in the U.S., made clear that the focus on driving Indian economic growth at 7.6% must “be achieved with a light carbon foot print, with greater emphasis on renewables.”13 In his meeting with President Obama, Modi also confirmed India would ratify the Paris COP21 Agreement this year. India pledged to cut its GDP carbon intensity by 33–35% compared to 2005 levels and bring renewable and nuclear capacity up to 40% of the total by 2030. Subsequently S&P Global Platts forecast that India’s reliance on coal-fired power generation would drop from an estimated 69% share in 2020 to just 60% by 2030—compared to a peak of 75% in 2015.

After Modi’s visit to the U.S., the Indian Energy Ministry announced the cancellation of four ultra-mega power plants (UMPP) in the states of Chhattisgarh, Karnataka, Maharashtra, and Odisha, with a combined capacity of 16 GW.14 These four proposed plants had been in the planning, preparation, and land acquisition stage for eight years. Community resistance to compulsory land acquisition and forced resettlement combined with electricity power surpluses helped persuade the government to cancel. It had been expected that the UMPPs would facilitate the proposed closure of 37 GW of old coal-fired capacity, and India appears to be going ahead with the closures even without these new coal plants.


The news of the UMPP cancellations has been complemented by signs that the government appears to be preparing the 13th Five-Year Plan (2017–2022) to call for the development of 100% supercritical technology for those plants that do get built. Anil Razdan, the former Secretary for Power, said an “efficiency tax” might be levied to encourage operators to upgrade their capacity. He also suggested that the coal levy (currently Rs 400/t or $6/t), which contributes to the Clean Environment fund, could be expanded to include clean coal technologies.15

Cost differences, however, could still impact developers’ choices. Analysis show that if all coal plants built from 2020 on were ultra-supercritical, total capital expenditure would reach US$500 billion by 2040, compared to around US$387 billion if all coal plants built from 2020 onward were subcritical.16

Supercritical clean coal technologies are an important component in India’s INDC (Intended Nationally Determined Contribution) for the COP21 agreement. If India is to drive economic development as planned through electrification, with 290 GW of coal- fired plants under construction or in the pipeline, a wholesale switch to supercritical plants is essential if emissions are to be kept down.17

CO2 emissions are 25–30% lower in a supercritical plant, making them a long-term, cost-effective option to reduce emissions. In addition, the technology lays the groundwork for carbon capture and storage (CCS). A report by the World Coal Association in late 201518 claims the cost of saving a tonne of CO2 would work out at around $10 per tonne by replacing subcritical (old) plants with supercritical and ultra-supercritical technology—
making it the most cost-effective form of CO2 abatement, allowing economic development and poverty alleviation efforts through electrification to continue at lowest cost.

Modernization of cities and the electricity system will increase electricity growth and efficiency.

Power: Sector Targets Higher Utilization and More Renewables and Nuclear

With the utilization rates of the average coal-fired power plant at multiyear lows of 61.6% in 2015/16,8 having fallen steadily since 2008, the government believes part of the reduction in coal-fired expansion plans can be covered by increasing utilization rates at existing plants. Among the factors constraining utilization are coal supply bottlenecks. A more reliable source of coal is needed, which could mean a shift in demand toward imports, which are often higher quality and more reliably delivered than the coal produced in India.

In addition, peak shortages have been falling quickly over recent years according to the Ministry of Power, indicating that supply is coming more in line with demand across the country. Anecdotal evidence, however, suggests the official figures may be overoptimistic, with blackouts and brownouts still common across the subcontinent. Nevertheless, the ministry said in June 2016 that this decline in peak shortages indicates it would not need any new thermal capacity for the next three years beyond what was already under construction. Figure 2 shows both the fall in utilization rates and peak shortages since 2006.

FIGURE 2. Falling utilization rates and narrowing supply deficits

Coal generation will face more competition from alternatives. India plans to ramp up solar power from 7.5 GW now (up from 10 MW in 2010) to 100 GW of capacity installed by 2022.19 This is a sharp increase in the 2009 target for 2020 of 20 GW, but could be attainable due to high solar intensity, cheap land, falling solar panel prices, and strong regional and central government support. In June the World Bank Group (WBG) announced more than US$1 billion in loans over FY 2017, the bank’s largest-ever support for solar power in any country.20 This stands in stark contrast to its decision not to support India’s higher efficiency supercritical coal-fired units. The WBG is also backing the India-led International Solar Alliance, aimed at promoting solar use globally by mobilizing US$1 trillion in investments by 2030.

While in Washington, Prime Minister Modi also agreed to Westinghouse’s plan to build six AP1000s nuclear plants in India,21 which could represent as significant a challenge to coal as intermittent solar. Nuclear power produces a steady baseload that has the potential to produce electricity less expensively than coal or solar. This is, however, conditional on the plants being built, and construction times and costs so far are longer and less certain than easily constructible coal-fired plants, adding substantial uncertainty to nuclear investment.

This deal is the first such opportunity for a U.S. company since the countries signed a civil nuclear agreement in 2008, partly due to the 2010 Indian law on nuclear liability (now remedied through India’s ratification of the Convention on Supplementary Compensation for Nuclear Damage). It could pave the way for further nuclear agreements between India and overseas investors.

A weaker international gas market could also present a challenge to coal. For instance, Essar Power, one of India’s largest private-sector power companies, is planning to restart two gas plants in western India that have been idle for three years.22 Essar expects lower gas prices to last for 5–8 years, although currently prices remain above the price of coal on a unit energy basis.

Coal: Rising Coal Stocks, Surplus Production, and Falling Imports

The state-controlled dominant producer, Coal India Limited, and its customers are facing a massive coal stockpile of 97 mnt, which needs to be consumed quickly to avoid fire risks.23 Figure 3 shows the rise in stocks since 2006. The total includes 58 mnt at Coal India’s mines and a further 39 mnt at its customers’ power plants. The company has cut prices of higher grade coal to encourage buying, but so far has been unable to shift the surplus, due to a lack of demand from plants.24 This lack of demand could be due, in part, to the ongoing drought that has seen a number of water-cooled coal plants shut down. Problems with domestic distribution, partly due to Indian coal’s high ash content, also make transportation more problematic.

Early in March, a senior official at Coal India said: “The power companies are not in a position to take any additional coal and we are being requested, both officially and unofficially, to cut supplies, which has prompted us to scale down production at several other mines apart from the ones where we have stopped production temporarily.”24 Around the same time, another Coal India executive was quoted as saying that cutting the price of coal to boost sales would have “far-reaching unfavourable implications” for the company’s profitability.25 Prices have been cut by 10–40% until the end of March 2017, as the company attempts to reduce stockpiles.

The price cuts could also provide a further challenge to coal imports, which fell by 15% to 132.3 mnt tonnes in nine months to January this year, from 155.4 mnt a year ago.8 For the second year running, NTPC, India’s largest power generator and coal consumer, will not import any coal this year. It plans to source its entire requirement of 155 mnt from domestic resources. In early July, the Ministry of Finance sought a presentation on the feasibility of power projects running on imported coal from the Ministry of Power, expressing concern that the cost of such projects could be subject to changes in law internationally following the COP21 agreement.

Electricity demand in India is increasing rapidly.

The situation could threaten the remaining plans to develop overseas mines for the Indian market, such as the Adani Group’s proposed 60-mnt Carmichael low-grade thermal coal mine in Australia. Before the recent price slump, a number of Indian companies—including Adani, Jindal, Reliance, and the ICVL consortium of NTPC, Coal India, and others—had begun plans for mines in Australia, Indonesia, South Africa, and Mozambique. But by undermining imports with low prices, Coal India should be well placed to take advantage of future growth, provided it can prove itself a reliable provider.


While Coal India attempts to undercut imports and shift stock, many smaller industrial consumers remain short of coal. In an attempt to overcome such bottlenecks, the Ministry of Coal has recently earmarked 16 coal mines to be allocated to states for sale to private companies—an important step in dismantling Coal India’s monopoly.

The states will then mine and sell coal to their own industries, helping curb the black market for coal that results from the supply shortfall. The ministry is in the “last lap of designing” a guiding mechanism for transparent mining and sale of coal by the states.26 So far, coal blocks allotted to the states under the new mechanism have stipulated end-use, and no sale of coal was allowed. Any commercial mining will have strict guidelines.

Depending on how successfully policy emphasis continues to move toward environmental priorities, the ambitious production target of one billion tonnes per year by Coal India by 2020 may not all be needed, and imports could be squeezed further. However, the current slide in imports and hiatus in coal plant construction is unexpected and may only be a temporary factor. The continuing fast-growing economy is likely to drive power demand sharply higher. This should increase utilization, absorb stocks, and provide a growing market for rising domestic coal production, while maintaining space for some imports—for the supercritical coastal plants at least.


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  16. Ebinger, C.K. (2016, 3 June). India’s energy and climate policy: Can India meet the challenge of industrialization and climate change? Brookings Energy Security and Climate Initiative. Available at
  17. IEA Clean Coal Centre. (2015, September). Summary: HELE perspectives for selected countries, India,
  18. World Coal Association. (2015, November). India’s energy trilemma,
  19. Sethi, N., & TNN (2009, 18 November). India targets 1,000mw solar power in 2013. The Times of India,
  20. The World Bank. (2016, 30 June). Solar energy to power India of the future,
  21. Lee, C.E., & Mauldin, W. (2016, 7 June). U.S. firm to build six nuclear reactors in India. Wall Street Journal,
  22. Sundria, S., & Chakraborty, D. (2016, 16 June). Essar Power in talks with Shell, GAIL for LNG to restart gas plants. Bloomberg,
  23. Mondal, D. (2016, 11 April). A problem of plenty: Huge coal stock pile up may lead to fire this summer. (an initiative of The Economic Times),
  24. Sengupta, D. (2016, 4 March). CIL stops work at several mines. The Economic Times,
  25. Kanungo, S. (2016, 29 January). Coal India likely to scale back production as stock piles: Piyush Goyal. LiveMint E-Paper,
  26. Jai, S. (2016, 17 March). Government opens up Coal India monopoly. Business Standard,


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A New Platform to Estimate Mercury Emissions

By Stephen Niksa
President, Niksa Energy Associates LLC

The U.S. utility industry has already installed mercury (Hg) emissions controls at hundreds of coal-fired power plants to meet the Mercury and Air Toxics Standards (MATS) that went into effect in spring 2016. Meanwhile, utility operators in the developing world are focusing on recent or impending regulations on particulates, SOX, and, perhaps, NOX. This is unfortunate because the global distribution of anthropogenic Hg emissions1 shows that the strongest sources of this air toxin coincide with a heavy reliance on coal for electricity generation. The situation is actually more complex because, taken together, artisanal and small-scale gold mining and coal combustion account for 60% of all anthropogenic Hg emissions, with gold mining’s contribution being about 50% greater than that of coal combustion. Whereas Hg control technologies are already being applied to power plants in developed countries, they will also need to be applied in developing countries to effectively reduce global emissions.

Through extensive research and development, state-of-the-art mercury control optimization systems are now available.

The United Nations Environment Programme (UNEP) has led global efforts to rein in Hg emissions from all sources, including establishing the multilateral Minamata Convention on Mercury.2 On the technical side of Hg emissions control, UNEP distributes the Mercury Inventory Toolkit3 that brings the skills and tools to monitor Hg emissions to local field testing teams, and has already guided teams at power plants in Russia, South Africa, India, China, Thailand, Indonesia, and Vietnam. UNEP supports statewide, regional, and local estimates for Hg emissions from power plants, and supports strategic planning on Hg emissions control at the scale of individual power plants. That’s the specific goal of its Interactive Process Optimization Guidance (iPOG) program. This user-friendly computer program gives nonspecialists and experts alike a simple means to estimate Hg emissions for actual and hypothetical fuels and gas-cleaning units at a specific power plant, based on the huge database of field test data recorded by U.S. utility companies. This article reviews the look-and-feel of the program, the input data requirements, and a case study that demonstrates iPOG’s capabilities.


Three forms of Hg are found in coal-derived flue gas: elemental mercury (Hg0); oxidized mercury (Hg2+), which is combined with chlorine or bromine; and particulate mercury (HgP), which is bound to fly ash. Flue gas contains suspended solids called fly ash that originate in two sources, either in the mineral matter embedded in the coal and released during combustion or as the unburned carbon (UBC). Only UBC has strong affinities for both Hg0 and Hg2+, and only in the presence of chlorine or bromine vapors. The imperative in Hg emissions control is to operate the cleaning system to convert as much Hg0 as possible into HgP and Hg2+. Particulate Hg is desirable because essentially all Hg adsorbed onto suspended particles in the flue gas stream is readily captured in a particle collection device. Whether a plant uses an electrostatic precipitator (ESP), a fabric filter (FF), or a venturi wet scrubber, it collects all the HgP that enters it.

An abundance of Hg2+ is preferable because the flue gas desulfurization (FGD) scrubbers that capture sulfur dioxide also collect all the Hg2+ entering with the flue gas, but none of the Hg0. Mercury captured this way ends up sequestered in the finest particles of gypsum, which is often a saleable byproduct in coal-fired electricity generation. So the keys to controlling Hg emissions are to (1) oxidize as much Hg0 into Hg2+ upstream of the FGD scrubber and (2) bind as much Hg0 and Hg2+ as possible into HgP upstream of the particle collector.

Controlling Hg emissions is a challenge for several reasons. Typical levels of coal-Hg are only about 100 ppb, and these levels are diluted by roughly a factor of 10 by the combustion process. To get a sense of how small such concentrations really are, imagine that a large football stadium was filled to the rafters with white ping pong balls. If a few handfuls of black balls were added to the stadium mix, they would be present at a concentration of 10 ppb or so, like the Hg0 concentration as it moves from the furnace into a gas-cleaning system. Mercury emissions control is like capturing only the black balls while the stadium is quickly evacuated through the gates.

Another obstacle is the daunting number of furnace and cleaning conditions that determine how much of the coal-Hg is captured or emitted (as explained in detail elsewhere4). If the level of chlorine in coal is not sufficient to bind the mercury to the UBC particles before the stream reaches the particle collector, or the chlorine and UBC in the flue gas are not in the proper proportions to maximize the conversion to HgP, then an operator may consider spraying a bromine solution onto the coal before it is fed into the furnace. Activated carbon can also be injected into the flue gas upstream of the particle collector to compensate for deficient UBC.

The third obstacle is that several technical approaches could potentially meet an emissions target, but at markedly different cost. The pace and depth of current and impending emissions regulations usually dictate whether the units that control particulates, NOX, and SOX will be able to meet the regulations on Hg emissions with only minor adjustments and additives, or whether dedicated Hg control technologies will be needed. The first scenario takes advantage of so-called co-benefits for Hg emissions control, whereas the second uses dedicated or external Hg emissions controls. Both forms of control can be analyzed with iPOG.


iPOG estimates the proportions of Hg0, Hg2+, and HgP at the inlets and outlets of every pollution control device in a gas-cleaning system. Users start with calculations for their current gas-cleaning configuration, and the properties of their current fuels. Once the baseline Hg emissions have been estimated, users can quickly estimate the emissions reductions for a broad assortment of control strategies. They can evaluate coal pretreatments based on washing or float/sink separations, and consider different fuel-blending strategies, and fuel switching. Either chlorine or bromine compounds can be virtually added to the fuel stream as it enters the furnace. Furnaces are specified by their burner arrangements, megawatts of electricity output, and overall thermal efficiency, plus the amounts of excess air and the percentage of UBC in fly ash. The flue gas-cleaning configurations can have any arrangement of a selective catalytic reduction (SCR) reactor for NOX control, particle control units (ESP, FF), and a FGD scrubber. Units also can be added or omitted at will, to assess the co-benefits for Hg emissions control from better controls on particulates, NOX, and SOX. The dedicated Hg emissions controls cover injection of chlorine or bromine compounds, and conventional or brominated activated carbon at any point along the gas-cleaning system.

The output screen in Figure 1 illustrates a typical calculation sequence. The flow diagram along the lower portion illustrates the user’s entries for the cleaning configuration. This case shows coal being fed into a 750-MW wall-fired furnace without any additives. The flue gas leaves the furnace and passes through an SCR for NOX control, an air preheater, ESP to remove fly ash, and a wet FGD scrubber for SOX control, before it enters the stack. Along the bottom, the diagram gives the Hg withdrawal rates in ash from the bottom of the furnace, in fly ash captured by the ESP, and in the scrubber solution from the FGD. In this case, hardly any Hg was withdrawn from the furnace, whereas almost 16% was collected with the fly ash, and 88% of the Hg coming into the FGD was retained in the wastewater.

FIGURE 1. Summary screen for iPOG calculations

Overall capture efficiencies are shown along the top of the screen in the figure. For these cleaning conditions, 95% of the Hg is oxidized along the catalyst in the SCR, so 95% of the flue gas entering the FGD is in the oxidized state. Stack emissions rates are given in g/h and g/TJ, along with the proportions of Hg0 and Hg2+ from the stack, and the overall Hg removal efficiency.


Gas-cleaning systems on coal-fired plants vary dramatically, and programs to estimate Hg emissions must describe all the popular configurations. Suppose, for example, that a newer 750-MW furnace operates at full load with a high-sulfur bituminous coal, and with an ESP to capture particulates but no other pollution controls. The UBC level in the fly ash is 3.5 wt%, which is a modest level, and the flue gas contains about 50 ppm chlorine. The plant operators are currently procuring a wet FGD to control SOX emissions, and contemplating an SCR for NOX control. The iPOG estimates the Hg removal co-benefits of these additional pollution control units, and can also evaluate coal washing and bromine addition to the coal feed. The estimated stack Hg emissions rates and overall Hg capture efficiencies for relevant iPOG runs are compiled in Table 1.

TABLE 1. iPOG assesses the co-benefits for Hg emissions control

Without any Hg capture, the emissions rate would be 47 g/h. The current ESP-only system emits 41 g/h, for a capture efficiency of only 14%. This Hg capture efficiency is not limited by the availability of coal-chlorine, since equal proportions of Hg0 and Hg2+ are released from the stack. Rather, it is limited by the availability of UBC to capture the Hg species before the flue gas enters the ESP. Washing the coal only lowers the emission rate to 38 g/h, and raises the capture efficiency to 19%. After the wet FGD is installed, the emissions rate decreases to 24 g/h, while the capture efficiency surges to 50%, because the scrubber captures the substantial portion of Hg2+ that would otherwise enter the stack. If a bromine solution were sprayed on the coal feed, however, the Hg emissions would slightly diminish to 20 g/h for a capture efficiency of 58%. However, the impact of adding an SCR is dramatic. The rate diminishes to only 5 g/h for a capture efficiency of just below 90%. Indeed, SCR catalysts are the most effective means to oxidize Hg0, which explains why SCR/ESP/FGD cleaning configurations provide the greatest co-benefits for Hg control.

Modern coal-fired power station with emissions control technology

iPOG allows users to formulate case studies on fuel switching and fuel blending, which is becoming more common throughout Asia where native coal supplies are outpaced by surging demand for electricity. Users can also delve deeper into the connections among coal properties, furnace performance, and Hg capture efficiencies. Policy analysts use iPOG to run numerous “What if?” scenarios across local and regional facilities. Ultimately, numerous case studies can be synthesized into a strategy to achieve the greatest Hg emissions reductions for the lowest cost that are compatible with specific constraints on coal quality and gas-cleaning configuration, and the timetable of impending Hg emissions regulations. From environmental managers, to fuel procurement specialists, to project engineers, to technology manufacturers, the numerous scenarios provided by iPOG streamline the path toward the most cost-effective approach to reducing Hg emissions. All stakeholders can obtain a copy of the program free of charge by contacting the Mercury Section at UNEP.


The statistical uncertainties on iPOG estimates have been analyzed in detail.5 The most general limitation is that the iPOG estimates are based on regressions of field test data, so they are no more accurate than the qualified measurement uncertainties, which are 10–15% of the total Hg inventory in each test. Differences among cases that are smaller than these tolerances are statistically insignificant and should be ignored. Since the input data requirements have been streamlined, iPOG cannot depict the distinctive features of particular gas-cleaning systems. This is particularly important in the results from activated carbon injection, which does not account for interference by adsorbed sulfur trioxide. Similarly, for oxidation of Hg0 along SCR catalysts, iPOG does not account for variations among the SCR design specifications and in the reactivities of the catalysts from different manufacturers and for different lifetimes in service. Users who reach a point in their analyses with iPOG where these limitations are hindering their development work on Hg control strategies can consider more comprehensive simulations.6


  1. United Nations Environment Programme (UNEP). (2013). Global mercury assessment 2013: Sources, emissions, releases, and environmental transport. UNEP.
  2. UNEP. (2016). Minamata Convention on Mercury, www.mercury
  3. UNEP. (2016). Toolkit for identification and quantification of mercury releases,
  4. Niksa, S., & Krishnakumar, B. (2015). Predicting Hg emissions rates with device-level models and reaction mechanisms. In: E. Granite, Pennline, & C.L. Senior (Eds.), Mercury emissions control for coal-derived gas streams (Ch. 27). Weinheim, Germany: Wiley-VCH.
  5. Krishnakumar, B., Niksa, S., Sloss, L., Jozewicz, W., & Futsaeter, G. (2012). Interactive process optimization guidance for mercury emissions control. Energy Fuels, 26(8), 4624–4634.
  6. Niksa Energy. (2016). MercuRator<supTM,


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The Future of Gasification

By DeLome Fair
President and Chief Executive Officer,
Synthesis Energy Systems, Inc.

Gasification technology has experienced periods of both high and low growth, driven by energy and chemical markets and geopolitical forces, since introduced into commercial-scale operation several decades ago. The first large-scale commercial application of coal gasification was in South Africa in 1955 for the production of coal-to-liquids. During the 1970s development of coal gasification was propelled in the U.S. by the energy crisis, which created a political climate for the country to be less reliant on foreign oil by converting domestic coal into alternative energy options. Further growth of commercial-scale coal gasification began in the early 1980s in the U.S., Europe, Japan, and China in the coal-to-chemicals market. The technology quickly transitioned into an alternative cleaner energy platform with the first coal-to-natural-gas project completed in the U.S. in South Dakota and the first integrated gasification combined-cycle (IGCC) project demonstration at Cool Water, California. In the 1990s the completion of the Polk and Wabash cleaner coal commercial IGCC power projects further advanced the technology. As energy prices continued to trend ever higher, the development of cleaner energy projects using coal gasification accelerated rapidly in the early 2000s.

Yima Night

Successful gasification projects demonstrate that viable markets exist.

In the U.S., this dynamic quickly changed with the ensuing drop in natural gas prices associated with the emergence of hydraulic fracking of shale for natural gas extraction. Development of coal gasification projects in the U.S. then slowed significantly, with the exception of a few that were far enough along in development to avoid being cancelled. However, during this time period and on into the early 2010s, China continued to build a large number of coal-to-chemicals projects, beginning first with ammonia, and then moving on to methanol, olefins, and a variety of other products. China’s use of coal gasification technology today is by far the largest of any country. China rapidly grew its use of coal gasification technology to feed its industrialization-driven demand for chemicals. However, as China’s GDP growth has slowed, the world’s largest and most consistent market for coal gasification technology has begun to slow new builds.

Recently, growth in the coal gasification industry in general has slowed as the global energy price landscape has shifted significantly. If the gasification industry continues to think about coal gasification as it has been historically defined (i.e., large projects focused on conversion of high-quality coal into mainly chemicals), I believe the future will continue to look challenging. But, if historical conventional thinking about the role of coal gasification is left behind, and market trends are carefully evaluated, I believe market and geopolitical forces are aligning to allow for a new wave of significant growth in coal gasification.


Fair Figure 1

FIGURE 1. Natural gas price projections1

The main competitors to coal gasification are oil- and natural gas-based energy and products and natural gas prices are the single most important indicator for the viability of coal gasification projects. When natural gas is inexpensive and plentiful, coal gasification projects are unlikely to be built. Figure 1 shows projections for liquefied natural gas (LNG) prices in Japan, natural gas prices in Europe, and natural gas prices in the U.S. Figure 2 shows the landed LNG prices around the world in early 2016.

Fair Figure 2

FIGURE 2. Landed LNG prices2

Looking at the information provided in these two charts, several key conclusions can be drawn:

  • With the exception of the U.S., natural gas prices around the world are expected to remain elevated well into the future.
  • While projected to be stable, natural gas is still subject to high volatility.
  • Although landed LNG prices shown are under $6/MMBtu, LNG regasification and pipeline transportation add additional cost before the fuel becomes available to the end user. For example, over the past year, I have seen natural gas prices in China ranging from 2.5 to 3.5 RMB/Nm3 ($10–15/MMBtu).

The bottom line is that natural gas prices in the areas of the world anticipated to have the highest growth (China, India, Indonesia, Brazil, Africa) are expected to remain high for the extended future. This sets the stage for an emerging large opportunity for lower cost alternatives to expensive natural gas and LNG, such as clean syngas from coal gasification, to enter the markets.


Canada and the U.S. are by far the highest users of energy on a per capita basis, although these numbers have decreased recently (see Figure 3). The European countries shown in Figure 3, while highly developed, have a lower energy utilization per capita. It is reasonable to assume that as developing countries continue to grow, they could eventually approach the energy utilization per capita of the EU.

Fair Figure 3

FIGURE 3. Energy use per capita in select countries3

China, for example, has already seen major increases in its per capita energy consumption over the last few decades, and additional growth is likely. With China’s population of about 1.35 billion people, increasing the energy per capita from the 2012 level to 5000 kWh (slightly lower than all the EU countries in 2012) would require about 250 GW of additional power generation capacity. For India, with a population of about 1.25 billion people, more than 600 GW of additional capacity would be required to achieve this level. These numbers do not take into consideration the additional power capacity required, due to further increases in population which are likely to occur in these countries. Additional electricity and fuel capacity will be necessary to meet the energy demand of these growing populations (see Figures 4 and 5).

Fair Figure 4

FIGURE 4. Global energy consumption predictions4

Figure 4 shows both a historical perspective and a future projection. Notably, the rate of growth in energy consumption for non-OECD countries mirrors the shape of the coal consumption curve shown in Figure 5. In fact, most of the growth in electricity capacity will be in the non-OECD countries, and these countries will use coal. Gasification can play a big role in this growth by providing low-cost, low-emissions clean energy from locally sourced coal with superior carbon capture retrofit capabilities, compared to traditional coal-based technologies.

Fair Figure 5

Figure 5. World energy consumption by fuel4


As power providers and governments make decisions about new power generation options, several key factors must be considered. First, a decision needs to be made regarding the fuel that will be consumed. Often, the most important selection factor is the cost of the fuel. In addition, considerations will be made regarding the long-term availability of the fuel, and the domestic energy security impacts of imported fuel versus domestic fuel. Finally, the emissions will increasingly be scrutinized as evidenced by the Paris Agreement resulting from COP21.

In parts of the world with a large discrepancy in the cost between natural gas and coal, it is highly likely that coal will still be selected, as it is economical and locally available. While developed markets will likely attempt to offset the carbon emissions from coal plants by building more expensive renewable technologies, such as wind and solar, the large emerging markets need economical and reliable new power capacity at large scale immediately. This dynamic has driven, and will likely continue to drive, large increases in the demand for coal-based power projects. Coal gasification can play a significant role because of its ability to generate economic, reliable power with very low levels of criteria emissions.

In the case of coal-fueled projects, a choice must be made between traditional pulverized coal-fired boilers and coal gasification-derived power. Key considerations will be the time required to build the plant, the capital cost of the plant, and the availability of low-cost financing. Another important decision will be the capacity of the plant. Traditional large-scale coal power generation plants capable of generating 600 MW and larger may not always be desirable, due to lack of centralized load demand and adequate long-range transmission capability. In these cases, smaller-scale power generation in the 50–300 MW range will be more desirable, due to the more distributed nature of load demands.

Criteria and greenhouse gas emissions are also important considerations. Coal gasification-derived power is capable of producing power with far lower criteria pollutant emissions, such as SOX, NOX, and particulate matter, compared to traditional pulverized coal. In addition, as CO2 utilization technologies are developed and demonstrated, existing coal gasification facilities will offer significantly less expensive and commercially demonstrated methods to retrofit for the capture of carbon.

Coal gasification-derived power cannot only compete in the electricity market, but can quickly grow into a leader for coal-based power in these markets. However, there are a couple of key requirements. First, the gasification technology must be able to economically gasify low-cost, low-rank coal (such as lignite, brown coal, or high-ash coal), and coal wastes. The power plants must generate electricity with criteria pollutants much lower than historical coal power production. And finally, coal gasification providers need to continue to educate and drive the message regarding the superior retrofit capability of carbon capture of gasification. While the coal gasification power plants being built in the near term may not include capture, the ability to retrofit operating plants to drastically reduce CO2 emissions at a low cost has significant value and hedges the investment risk in a carbon-constrained world.

Coal gasification technologies exist that can fill the needs of the power market. For example, Synthesis Energy Systems (SES) has developed a small-scale, coal-fed power generation product. This new product, iGAS, combines the superior low-rank coal capability of SES Gasification Technology (SGT) with small-scale gas turbines for the production of low-cost, low-emissions power on a distributed power platform.

Yima Day

The coal-to methanol Yima Joint Venture Plant is successfully employing SES Gasification Technology (SGT).


In addition to the production of electricity, coal gasification can be used to generate other forms of energy. Two emerging markets are the production of substitute natural gas (SNG) and the production of syngas to replace natural gas or other fuels in industrial applications. Gasification for the production of SNG can be profitable, if the price of the coal is low and the price of alternative natural gas is high. However, this will still likely be more of a niche opportunity, with plants built at the coal source with access to existing natural gas pipeline infrastructure.

A new and emerging market for gasification is the use of low-priced coal to generate clean syngas that can be used directly as a fuel in an industrial setting, such as in the production of ceramics, glass, or aluminum. SES’s initial three such projects—licensed by its China Joint Venture, Tianwo-SES Clean Energy Technologies Company—were announced in December of 2014. The first of these projects started up in July 2015, and is estimated to save the Aluminum Corporation of China (the facility owner) more than $50,000/day in fuel costs for its aluminum products. Syngas can also be used to replace natural gas in the production of direct reduced iron in the steel industry.


What does the coal gasification industry need to do to capture a share of this large potential energy market? First, it needs to change focus from producing chemicals to producing clean energy. Chemical production projects will still be built, but I believe the real growth opportunity is in clean energy. Second, the industry needs to readjust its geographic focus. Historically, the location for coal gasification projects has been centered in eastern China and the U.S. China will still dominate as a major market for coal gasification, but next-generation markets will expand to include all of Asia, including countries such as India, Indonesia, Mongolia, Pakistan, and Vietnam. In the longer term, there will also be demand for this technology in other developing markets such as Brazil and Africa.

Finally, it is likely that many of the next-generation gasification projects will not be built by large-scale companies and government-owned entities with ready access to capital and financing. Coal gasification technology providers will need to expand beyond the traditional role of supplying license and equipment, to being able to provide turn-key gasification islands and become more involved in assisting the project developers in securing equity and financing to help these projects get started. With the favorable economics of these clean energy projects, equity investment by the technology pro-viders themselves can also be a very lucrative opportunity.


In summary, several key conclusions can be taken away from this analysis:

  • Market forces in high-growth regions are more aligned than ever with the capabilities of gasification technology.
  • Coal gasification technology providers have a great opportunity in large, high-growth mega-markets of energy.
  • Gasification is a clean energy technology.
  • Coal will be utilized heavily to fuel much of the global growth.
  • Gasification is the best option for coal in a CO2-constrained world.
  • Project decisions will be driven by (1) speed, (2) low CAPEX, (3) economics, and (4) environmental performance related to criteria emissions, capability for CO2 capture retrofit, and water consumption.

Coal gasification technology providers that have aligned their focus to take advantage of this unique combination of market dynamics and changing customer requirements will be successful. At SES, we believe our technology has the ability to meet the energy needs of the future and continue to utilize coal, the world’s largest energy resource, to provide clean energy to those who need it most.


  1. International Monetary Fund. (2015, October). Natural gas prices: Long term forecast to 2020, data and charts, com/ncszerf/natural-gas-prices-long-term-forecast-to-2020-data-and-charts
  2. Waterborne Energy, Inc. (2015). World LNG estimated December 2015 landed prices,
  3. World Bank. (2016). Electric power consumption (kWh per capita),


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Polygeneration as a Means to Reduce Energy Poverty in Pakistan

By Irfan Ali
Chairman, TharPak

Pakistan, the world’s sixth most populous country, is a developing nation facing many challenges. Over the last 12 years regional conflicts have taken a considerable toll on Pakistan’s economy and have left the nation with a damaged and vastly neglected infrastructure. The energy sector has been one of the most affected segments and is in desperate need of investment and revitalization. In 2012, the country, with a population of around 178 million, produced only 80 billion kWh of electricity; compare that with the Netherlands, which produced 115 billion kWh of electricity in 2012 for a population of only 16.7 million people.1

With the 2013 peaceful democratic transition of government for the first time, Pakistan is finally poised to begin providing more opportunities for its people, including increased public safety, stronger economic performance, better employment opportunities, and greater access to reliable energy. Improving energy production, utilization, and access will be the building block on which other development objectives can be founded.

Ali Opening Image

A shopkeeper carries lanterns to his shop to keep it open during electric load shedding.


Pakistan has been experiencing an energy crisis for decades and no aspect of the energy sector is untouched by this crisis. The country relies heavily on imports for its energy supplies. In fact, 44% of Pakistan’s energy supply is currently imported—at an annual cost of around US$15 billion.2 The utilization rate for the existing electricity sector, which relies on oil, natural gas, and hydro power, was less than 60% in 2012.3 This left 56 million people without access to electricity.

Natural gas is an important contributor to Pakistan’s primary energy mix, providing 32% in 2012.3 The giant Sui gas field has historically met the majority of the country’s natural gas demand. From the time of its discovery in the early 1950s, production from Sui drove the development of a natural gas distribution system that now extends across the nation. However, as the Sui reservoir depletes at an increasing rate, there are challenges associated with expanding domestic natural gas production.

Although the country produced 1412 billion cubic feet (bcf) of natural gas in 2013, this fell far short of the amount needed. Without reliable natural gas, even households with a connection to the distribution lines were forced to collect biomass to heat their homes and cook. This led to tremendous amounts of in-home pollution and an alarming rate of deforestation. Thus, Pakistan is now looking to build new pipelines so that it can import natural gas and is also pursuing the construction of liquefied natural gas (LNG) facilities. The country also has 105 trillion cubic feet of shale gas, but economic production is unproven and faces technical and economic challenges. Attempting to increase the role of natural gas in Pakistan’s electricity sector could very well increase the country’s already-high reliance on energy imports.

The once-abundant supply of natural gas spawned the world’s largest natural gas-fueled vehicle count on the roads of Pakistan. Filling stations offering compressed natural gas (CNG) were built throughout the country and CNG car conversion kits were so affordable that low-income taxi drivers converted their vehicles. At least two million vehicles in Pakistan run on natural gas and about 3000 CNG stations are in business today.4 Although diesel dominates the market for transportation fuel, the transport sector also has strong demand for natural gas, which may be poised to grow further if the country can secure new supplies.4 Currently, the government is discouraging natural gas for transportation given the country’s shortfalls of the fuel. When the decline in Sui production started accelerating around 2012 mile-long lines at CNG stations appeared. As a result, many drivers have been forced to return to more expensive gasoline or diesel.

Motorists wait in long queues to fill up at a CNG station in Larkana.

The country, like most, is working to phase out oil-fired power plants. Such plants are subject to the extreme volatility in oil prices and also make the country’s electricity sector more heavily reliant on imported oil. Hydro power provides about 30% of the electricity in Pakistan, but is not reliable during summer. The government intends to grow the electric capacity of renewables, such as wind and PV solar, to account for about 15% of its electricity mix, but the intermittency eliminates them as near-term options for baseload power.2

Pakistan’s coal reserves are hugely underutilized. The Thar coalfields are estimated to hold about 175 billion tons of low-rank coal that is yet to be mined.2 Although sufficient infrastructure is not currently in place, the Thar coal resources could probably support 100 GW of electricity production for 200 years. At a time when power shortages in Pakistan are estimated to cost the economy 2–4% of GDP growth and lead to closure of factories and other important employers, harnessing this indigenous fuel is increasingly attractive.3

Notably, there are other issues with the electric sector that must be addressed. Transmission and distribution losses are close to 22%. Theft must also be curbed as well as a long-standing circular debt problem plaguing independent power producers. All the issues facing the electric sector result in load shedding of several hours per day, and Pakistanis pay about double for electricity compared to their Indian neighbors.5 While much work remains, I believe the energy sector reforms being undertaken, such as establishing a special tariff for Thar coal used in electricity production, tackling the circular debt issue by the current government along with streamlining permitting are encouraging and these challenges are finally being addressed with the urgency they warrant.


While alleviating energy poverty and providing energy to support economic growth are major goals, energy development in Pakistan must be carried out in a manner that minimizes the environmental footprint.

Increased domestic natural gas and coal production could support a revitalization of Pakistan’s energy sector. Although energy production is often associated with a detrimental impact to the environment, if Pakistan’s energy resources are developed in a responsible and rational manner, there could be considerable environmental benefits not just for Pakistan, but to also help meet global objectives. As indicated earlier, the decline in Sui production, which began to gain momentum around 2012, has led to natural gas shortages and forced a large number of Pakistanis to gather biomass for heating and cooking; the country’s tree cover is now estimated to be 2–5% of what it once was.6 This has led to flooding, landslides, and other major environmental disruptions. In addition, when biomass is burned indoors it releases dangerous chemicals. In this way, reliable energy fueled by indigenous resources could immediately benefit Pakistan’s environment.

The first permits for mining the Thar coalfields are moving forward. In addition, developers have opted to build a circulating fluidized bed (CFB) for the first coal-fired power plants using Thar coal.2 Using CFBs is important because they can successfully utilize low-rank coal like that found in the Thar coalfields. Emissions are also more easily controlled using CFBs, because they produce less NOx due to lower temperature operation, and limestone in the boiler immediately captures most SOx. While this is an important first step, CFBs and other coal-fired power plants are not able to address the need for additional natural gas. In addition, CO2 emissions would need to be mitigated through carbon capture and storage (CCS). However, there is a way that Pakistan can use its large coal resources to meet energy needs beyond electricity generation and largely mitigate criteria emissions as well as CO2.


Several project developers are looking to produce and utilize the coal resources in the Thar coalfields. One innovative example is TharPak, LLC, a consortium of clean energy companies aiming to deploy a suite of technologies including the use of gasification-based polygeneration to produce synthetic natural gas (SNG) and electricity for Pakistan in an environmentally sustainable manner.

Three specific technologies are envisioned as part of the TharPak project. First, the DryFining™ process, which has been developed and demonstrated by Great River Energy in the U.S., will be applied to dry the low-rank Thar coal prior to gasification. This process utilizes waste heat in a fluidized bed process that removes moisture and some sulfur and mercury from coal. This dried coal is also rendered more stable, can be economically transported over longer distances, and is less prone to spontaneous combustion. The DryFiningTM process has been profiled previously in Cornerstone.7

Second, KBR’s transport reactor integrated gasifier (TRIG™) will convert the treated low-rank, high-moisture coal into syngas (CO + H2). TRIG has been demonstrated on low-rank coals and is now commercially available. The syngas can be converted into synthetic natural gas (SNG) and/or electricity. The criteria emissions from the process are lower, and the CO2 emissions can also be captured, used, and/or stored to generate low-emissions energy. In the process used to make SNG, the CO2 must be separated, making its capture far more economical than conventional methods.

TharPak aims to use some of the captured CO2 in Algenol’s algae-based process, which can generate liquid fuels as a product at a projected cost of $1.30/gallon.8 The CO2 emissions can also be captured and processed for use in enhanced oil recovery (CO2-EOR) using commercially available processes.


TharPak plans to use processes that rely on algae to capture some of the CO2 from its polygeneration plant (lab-scale shown here).

An added benefit of the Algenol process is that it uses saline water and produces two gallons of fresh water for each gallon of fuel produced. There are several large salinated aquifers between the coal seams of the Thar field that are estimated to be the size of giant lakes. The area around is not only arid, the population is among the poorest in Pakistan and an abundant clean water source could help transform the area with agricultural uses year-round. Thus, TharPak’s combination of these proven advanced technologies can help meet demand for electricity and natural gas, while also capturing CO2 emissions. It is also worth mentioning that several heavy oil fields in the vicinity of the Thar coalfields which have been in production since the 1960’s could be recipients of some of TharPak’s CO2 to aid in CO2-EOR.

Integrated gasification and combined-cycle (IGCC) facilities that produce electricity exclusively have faced economic headwinds abroad. IGCC will be deployed to produce electricity only if it is economically competitive. Low costs for coal production and lower labor rates in Pakistan could enable economic IGCC even as it has been overly expensive elsewhere.

The SNG being produced would need to compete with new sources of natural gas for Pakistan, including expensive LNG. Based on initial estimates, TharPak is confident that, even at the current low prices in the LNG market, the SNG produced by its process will be competitive. Less dependency on imported fuel would add to Pakistan’s energy security and avoid the other environmental risks associated with transporting fuels long distances.

TharPak has been allocated Block IX of the Thar coal resource and is now working to secure the capital needed to advance the project. Although most development banks and other NGOs do not support developing Pakistan’s coal resources, there is a strong argument for doing so, especially if environmental concerns are addressed throughout the process.

There are few roads and little development in the Thar desert in Pakistan, but the coal resources found in the region have the potential to help alleviate the country’s energy crisis and revitalize the region.

There are few roads and little development in the Thar desert in Pakistan, but the coal resources found in the region have the potential to help alleviate the country’s energy crisis and revitalize the region.

There is a silver lining in the extensive delay in addressing Pakistan’s energy crisis. Technologies that were not commercially available only a few years ago now exist that can use the low-rank coal in Pakistan to help solve the energy crisis without major environmental disruption. In fact, the environment will arguably be helped through development of Pakistan’s coal resources through a diminished reliance on deforestation-causing biomass harvesting and eliminated the emissions from burning that biomass. The international community only needs to support such energy projects that could dramatically improve the lives of the Pakistani people. I believe that TharPak’s proposed coal-based polygeneration project is one such project.


  1. World Bank. (2015). Economic indicators 2012,
  2. Mansoor, K. (2015). How coal can help address Pakistan’s energy crisis. In: M. Kugelman (Ed.), Pakistan’s interminable energy crisis: Is there any way out? Woodrow Wilson Center for Scholars, p. 41,
  3. S. Energy Information Administration. (2015). Pakistan: International data and energy analysis,
  4. International Energy Agency. (2010). The contribution of natural gas vehicles to sustainable transport,
  5. Kugelman, M. (2015). Easing an energy crisis that won’t end, In: M. Kugelman (Ed.), Pakistan’s interminable energy crisis: Is there any way out? Woodrow Wilson Center for Scholars, p. 2,
  6. Craig, T. (2014, 2 February). Energy shortages force Pakistanis to scavenge for wood, threatening tree canopy. Washington Post, (accessed January 2015).
  7. Sarunac, N., Ness, M., & Bullinger, C. (2015). Improving the efficiency of power plants firing high-moisture coal. Cornerstone, 3(1), net/improving-the-efficiency-of-power-plants-firing-high-moisture-coal/
  8. S. Department of Energy. (2015, 2 October). Algenol announces commercial algal ethanol fuel partnership,

The author can be reached at


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