Country profiles report on the key coal-producing countries of the EU and its neighbours. This webpage examines the other EU member states that all use coal to a greater or lesser extent. Also included, because of their alignment towards EU energy policy, are the contracting parties and observers to the Energy Community.
The 2005 treaty establishing the Energy Community requires contracting parties to implement important parts of the EU acquis on energy markets and environmental protection. It provides for the creation of a single energy market and a mechanism for the operation of networks in the South East European region which disintegrated following the conflicts of the 1990s. In 2011, the contracting parties agreed to implement the EU’s third internal energy package by January 2015, although parties are not obliged to join the EU emissions trading system.
The Energy Community offers opportunities to owners of coal-fired power plants in South East Europe who will gain access to what is the world’s largest electricity market. At the same time, plant owners will be required to make very substantial investments in pollution control equipment to meet stringent EU emissions legislation.
Armenia is a landlocked country in the South Caucasus region, between the Black Sea and the Caspian Sea. In 2017, the majority of the country’s energy supply of 4.6 million tonnes of coal equivalent was imported from Russia, including fossil gas and nuclear fuel for the 376 MW nuclear power plant at Metsamor, 30 km from the capital Yerevan. The main domestic energy source is hydroelectricity. Electricity generation of 7.8 TWh came from roughly equal shares of fossil gas, nuclear and hydro. Total hard coal resources are 317 million tonnes and small deposits of oil and gas exist, but have barely been exploited.
Austria has limited primary energy resources and is dependent on energy imports for around two thirds of its primary energy supply. Although no longer exploited, lignite resources total 333 million tonnes, lying mainly in western Styria, near Graz.
During the Monarchy, the country’s energy demand was largely met with coal from Moravia and Silesia. After each world war, hard coal and lignite mining in Austria was expanded to replace production lost elsewhere; lignite output peaked at over 6 million tonnes in 1963 when hard coal output was 100 thousand tonnes. However, with increasing trade and the trend towards greater oil and fossil gas use, Austria’s underground hard coal mines became less competitive and were closed during the 1960s. After more than two centuries, Austrian coal mining ended in 2006 with the re‑cultivation of Oberdorf lignite mine.
Poland, the Czech Republic, the United States, Russia and Australia are the main coal exporters to Austria. In 2018, 3.5 million tonnes of coal were imported, mostly by the power and steel industries. The integrated steel works operated by VOESTALPINE at Linz has an annual crude steel production capacity of 5 million tonnes.
Electricity generation from coal was 3.6 TWh in 2018. However, on 2 August 2019 after almost thirty-three years, EVN ended coal-fired power generation at the 352 MW Dürnrohr power plant in Lower Austria. This followed the closure in April 2015 of a 405 MW unit owned by VERBUND at the same site. A 35 MW (210 MWth) waste-to-energy plant, completed in 2010, continues to operate at Dürnrohr. At Mellach, VERBUND’s 225 MWe coal-fired heat and power plant supplies the city of Graz with district heating. Some progress is being made on repurposing these coal power plant sites for hydrogen production, energy storage, renewable electricity generation and other activities.
The neighbouring states of Estonia, Latvia and Lithuania lie between the Baltic Sea and Russia. In 2004, these former Soviet states joined the EU and by 2015 all had joined the eurozone. To their south, the Russian enclave of Kaliningrad Oblast borders Lithuania and Poland.
Estonia, Latvia and Lithuania are poised to synchronise with the continental European electricity network in 2025, after gaining formal approval from the European Network of Transmission System Operators (ENSTO-E) in May 2019. Four DC links are already operational: LitPol, NordBalt, Estlink 1 and Estlink 2. The Baltic States will be desynchronised from the Russian IPS/UPS network, leaving Kaliningrad isolated unless DC links are built or the enclave joins the ENTSO-E system.
While no coal is produced in the Baltic States, all three countries consume modest volumes of imported coal, mostly from Russia, and offer important transit routes for Russian coal exported elsewhere.
Estonia is uniquely dependent on indigenous oil shale for its energy supply and enjoys an energy import dependency of just 4.1%, by far the lowest in the European Union. Large quantities of oil shale are used to generate competitively priced electricity at thermal power plants where it is combusted in much the same way as coal – either as a pulverised fuel in older boilers or in new circulating fluidised-bed boilers (CFBs).
Oil shale is a sedimentary rock containing up to 50% organic matter – Estonian oil shale extracted from the Baltic kukersite deposit has a heating value of 8 000-11 000 kJ/kg and 1.5% to 1.8% sulphur content. Once extracted from the ground, the rock can be either used directly as a fuel in power plants or processed into petroleum products.
Estonia’s accessible oil shale reserves total approximately one billion tonnes. In 2018, 15.9 million tonnes of oil shale (4.4 Mtce) were mined by EESTI ENERGIA and VIRU KEEMIA GRUPP at underground mines and by EESTI ENERGIA, KIVIÕLI KEEMIATÖÖSTUS and KUNDA NORDIC TSEMENT at surface mines. In underground mines, the traditional room-and-pillar mining technology is used. To improve recovery rates and reduce production losses, EESTI ENERGIA is developing a 700‑metre long-wall mining face at an underground mine.
At the beginning of the century, oil shale production was trending upwards to meet growing demand for oil products produced from oil shale. In response, the Estonian government set in 2018 an annual limit for oil shale mining of 20 million tonnes.
In 2018, Estonia generated 10.7 TWh or 83% of its gross electricity supply of 12.9 TWh from oil shale and oil shale gas, a share that is expected to decrease in the future in line with government policy to increase the share of renewables. Around 75% of oil shale production is used for electricity and heat generation, notably at the EESTI ENERGIA Narva energy complex, comprising the 1 615 MW Eesti power plant and the 405 MW Balti power plant which also supplies heat to the town of Narva. Final commissioning of the adjacent 300 MW Auvere power plant was completed by GE in September 2018; it runs on oil shale, biomass, peat and oil shale gas. Four of the eight old units at the Eesti power plant were placed in standby reserve in 2019 due to the high price of allowances under the EU emissions trading system.
The environmental issues associated with oil shale exploitation are complex. With 45% incombustibles, the quantities of ash to store or recycle are large. All old pulverised-fuel boilers operate under limited lifetime derogations or have been upgraded to comply with the EU Industrial Emissions Directive. Balti 11 and Eesti 8 were repowered with CFB boilers and further units have been fitted with a novel integrated desulphurisation system, supplemented with lime injection and deNOx systems.
7 303 people are employed in the Estonian oil shale industry, of which around 3 000 are employed at mines.
Latvia transhipped 20.9 million tonnes of Russian coal exports in 2018: total coal exports from Russia to the EU in 2018 were 67.8 million tonnes. Shipments through the Baltic Coal Terminal at Ventspils were 3.6 million tonnes – lower than the terminal’s annual capacity of 6.0 million tonnes as Russian ports were favoured by exporters. Ust-Luga, 120 km west of St. Petersburg, has become the largest port for coal in the region, although ice can hinder operations there as well as at St. Petersburg and Vyborg (Vysotsk) ports. Alternative routes for Russian coal exports include the ports at Tallinn (Muuga) in Estonia, Riga and Liepāja in Latvia, Klaipėda in Lithuania and Kaliningrad. Klaipėda port is strategically important as the northernmost ice-free port on the eastern coast of the Baltic Sea, with good infrastructure links to Russia. A proposal to expand the Russian Port of Primorsk to handle 25 million tonnes of coal per year would further reduce coal transhipments via the Baltic states.
The population of Lithuania has fallen by 17% since the country joined the European Union. Primary energy demand has thus declined to less than 10 million tonnes of coal equivalent in 2018. The country’s energy mix is dominated by imported oil and fossil gas, with only 264 thousand tonnes of imported coal in 2018.
The closure of the Ignalina nuclear power plant at the end of 2009 left a power generation gap in the Baltic region. This could have been filled by the proposed Visaginas nuclear power plant, but Lithuanians vote against this project in a 2012 referendum. Meanwhile, the 2 400 MW Ostrovets nuclear power plant, 50 kilometres from Vilnius, is under construction in Belarus, with pre-commissioning of the first unit taking place since April 2019. Commissioning of the second unit is scheduled to begin in 2020.
The Kaliningrad enclave is dependent on imported energy from Russia, although power is generated locally at the 900 MW gas-fired Kaliningradskaya power plant completed in 2010. To ensure power supply security, the 455 MW Pregolsky gas-fired unit was commissioned in March 2019 as the largest of four new plants with a combined capacity of 1 000 MW: the gas-fired Mayakovskaya and Talakhovskaya plants totalling 312 MW started operation in March 2018, while the coal-fired Primorsky plant should be completed by 2020. The latter will act as a backup. Gas is supplied via a single pipeline from Russia or from a new floating LNG storage and regasification unit. An underground gas-storage reservoir created in salt caverns provides additional security and will be expanded to hold 800 million cubic metres of gas. In May 2019, Kaliningrad’s power grid was temporarily run in isolation to demonstrate its readiness for the future.
Although construction stopped in June 2013 of a new 2 400 MW nuclear power plant at Neman close to the Lithuanian border, it would remain a viable project if customers for its electricity could be found in Germany, Poland and the Baltic states. With three years of civil works completed, major pieces of power plant equipment delivered to the site are being kept in storage, although in 2017 the pressure vessel for unit 1 was sent to replace a damaged vessel at the Ostrovets 2 nuclear power plant in Belarus.
In the 19th century, the Walloon coal mines of southern Belgium fuelled the country’s industrial expansion. By 1917, coal mining had started in the north-east, around Limburg. National coal production peaked at 30 million tonnes in 1952 and was maintained at this level until the late 1950s. Output gradually declined as the Walloon and Limburg mines closed: Eisden mine in 1987 and Belgium’s last colliery at Heusden-Zolder in 1992. Remaining hard coal resources are estimated to be 4 100 million tonnes.
Coal imports totalled 4.1 million tonnes in 2018, coming mostly from Russia, Australia and the USA (more coal is imported into Antwerp for onward delivery to customers in other countries). Coal provides about 6% of Belgium’s primary energy supply and is used mainly by the steel industry, notably by ARCELORMITTAL at Ghent. With the decommissioning of Ruien coal-fired power plant in 2013 and the conversion of other coal plants to fire biomass, coal consumption for power generation is no longer significant.
Gross electricity generation in 2018 totalled 75.0 TWh of which 28.6 TWh (38.1%) came from nuclear power stations, 23.8 TWh (31.7%) from gas-fired plants, 11.5 TWh (15.3%) from wind and solar, and 6.8 TWh (9.1%) from biomass and waste. Coal (3.1%), hydro (1.7%, mainly pumped hydro) and oil (0.2%) largely accounted for the remainder. Electricity imports have risen fivefold since 1990 to 21.6 TWh in 2018 due to capacity closures and lower power prices in France, Germany and the Netherlands. Belgium’s largest power utility, ELECTRABEL – a subsidiary of ENGIE – has investments in coal-fired power plants in the Netherlands.
Cyprus imports small, but growing quantities of hard coal – 22 thousand tonnes in 2018 – for use mainly by VASSILIKO CEMENT WORKS. For its electricity needs, Cyprus is reliant on heavy fuel oil imports costing over 8% of its GDP. Invitations to tender for an LNG import facility were published in 2017. The Maltese government is promoting the 2 GW EuroAsia Interconnector with Israel and Greece which would further diversify energy supply. Significant gasfields in the Levantine basin are now being exploited and if political tensions in the region ease, then Cyprus could exploit the Aphrodite and Calypso gasfields.
With the rise in its oil and gas production from the North Sea, Denmark became energy self-sufficient in 1999 and, in 2004, a net exporter of primary energy. The country is the third largest oil producer in Western Europe, after Norway and the UK. Gas production in 2018 was 4.1 billion cubic metres, less than half its 2005 peak. Oil and gas production are in decline and Denmark returned to being a net energy importer in 2013. In 2017, Denmark had the second lowest energy import dependence (11.7%) of any EU member state.
Danish energy supply has changed significantly as a result of efforts to promote renewable energy, combined heat and power (CHP) and energy efficiency. All political parties reached an energy agreement in June 2018. This is expected to result in a greater than 100% share of renewables in electricity supply by 2030, while ensuring that at least 90% of district heating is based on energy sources other than coal, oil or gas by 2030. The government’s long-term goal is for a climate-neutral Denmark by 2050.
In 2018, around 70% of gross electricity generation was from renewable sources, predominantly from wind and biomass. The relatively high use of wind turbines for electricity generation (46.3% in 2018) enhances security, but poses balancing challenges. The Danish electricity system has connections to Norway, Sweden and Germany: Denmark’s net electricity imports in 2018 were 5.2 TWh or 15.4% of supply. As part of the integrated Nordic electricity market, Denmark’s thermal power plants play an important role in balancing not only wind power, but also hydro power from Norway and Sweden which depends on annual precipitation.
Coal-fired power plants in Denmark have a total generation capacity of 3.7 GW; many are multi-fuelled with biomass. The majority state-owned ØRSTED runs Asnæs (827 MW), Avedøre (262 MW), Esbjerg (417 MW) and Studstrup (700 MW) power plants. Most units at these plants can burn biomass – wood pellets or straw – the result of ØRSTED’s bio-conversion programme for all its coal- and gas-fired CHP units which will see coal use end by 2023. The 319 MW Amager power plant is owned by HOFOR, the city of Copenhagen’s municipal heat and power company. HOFOR plans to replace its coal use in 2020 when a new biomass unit is commissioned – BIO4 has been under construction since September 2016. Fyn power plant (409 MW) includes a straw-fired boiler and a coal-fired unit, with the latter set to close by 2025. Finally, since 2015, the 410 MW Nordjylland plant has been owned by the local municipality’s utility company, AALBORG FORSYNING.
Nordjyllandsværket 3 is one of the world’s most efficient coal-fired power plants. Its supercritical boilers and steam turbines result in a very high electrical generation efficiency of 47% and, with heat supply, the overall efficiency can exceed 95%.
Denmark has no indigenous coal resources. In 2018, the country imported 2.8 million tonnes of coal, mostly from Russia, South Africa and Colombia. Around 95% of this coal was used for electricity and heat generation. Having peaked in 1984 at 96%, the share of coal in power generation has fallen to 21.4% in 2018 (6.4 TWh) and will be gradually phased out by 2030 under the June 2018 agreement.
With its lack of fossil fuel resources, Finland had an energy import dependency of 44.0% in 2017. Finnish energy policy thus aims to maximise energy supply diversity. One third of electricity production is from nuclear and Finland’s fifth nuclear reactor, a 1 600 MW EPR, is under construction at Olkiluoto with commercial operation by TVO scheduled for July 2020. In June 2015, TVO shareholders resolved not to proceed with plans for a second new unit at Olkiluoto. Locally produced peat (6.4 million tonnes in 2018) is used as a fuel, mainly at dedicated district heating plants and at combined heat and power (CHP) plants. Peat accounted for 4.8% of gross electricity generation in 2018.
Finland is one of the world leaders in renewable energy, especially bio-energy. Renewable energy sources provide over 40% of Finland’s total primary energy supply and accounted for over 35% of power supply in 2018. Nevertheless, coal and fossil gas remain important fuels for CHP and district heating plants in Finland. Coal’s share in conventional generation is falling. In 2018, gross electricity generation from coal was 6.6 TWh (9.4% of total), with an important contribution from the 565 MW Meri-Pori coal power plant at Tahkoluoto in Pori. The efficiency of heat and power production in Finland is very high; approximately one third of electricity is produced at CHP plants which operate with overall efficiencies of 80% to 90%. These plants are used widely by industry and for both district heating and cooling.
Annual coal imports to Finland were 4.0 million tonnes in 2018: 2.7 million tonnes of steam coal for energy production and 1.3 million tonnes of coking coal for the steel industry. Small quantities of coal are used by the cement industry. All coal is imported, steam coal entirely from Russia and coking coal mostly from North America.
Finland’s Integrated National Energy and Climate Plan is based on two government reports: the National Energy and Climate Strategy for 2030 and the Medium-term Climate Change Plan for 2030. The strategy accounts for Finland’s special features, including its cold climate, long transport distances, extensive energy-intensive industry and domestic raw material resources, especially forest biomass. To implement the strategy, Finland has taken many measures, in particular energy-efficiency and energy-saving measures, and plans to increase the share of renewable energy in final consumption to 50% by 2030. As well as the increased share of renewable energy, the government aims to maintain the position of peat as an indigenous energy resource, but to diminish the share of fossil fuels, in particular coal. Therefore, the government has tabled legislation to ban coal use for energy from 1 May 2029, except when used as an emergency backup fuel. Many coal-fired power plants are already phasing out of coal.
Coal resources in France are estimated by the French geological survey (BRGM) to be 425 million tonnes of hard coal and 300 million tonnes of lignite. Hard coal mining in France ended in April 2004 with the closure of the last operational mine, La Houve in the Lorraine region. The state-owned coal company Charbonnages de France ceased activity at the end of 2007. Today, all coal is imported.
In 2018, coal imports amounted to 13.5 million tonnes, including 4.6 million tonnes of coking coal from Australia and the United States. Coal is delivered through the ports of Dunkerque, Le Havre, Rouen, Montoir and Fos-sur-Mer, as well as via the ARA ports. Coal consumption amounted to 13.2 million tonnes in 2018, of which an estimated 3.9 million tonnes were consumed for power generation.
Gross power generation in France was 580.7 TWh in 2018, with 71.1% of this total generated at nuclear power plants. Conventional thermal power generation contributed 9.9%, hydro 11.2%, wind 4.9% and solar PV 1.8%. Coal-fired power generation accounted for 1.6% of the total while the overall share of renewables was 18.9%.
In compliance with the Large Combustion Plants Directive, the number of operational coal-fired power generation units in mainland France was reduced to five in 2015. According to the Programmation pluriannuelle de l’énergie published in November 2018, the French government wants to end coal-fired power generation by the end of 2021.
Today, the largest coal power plants are located adjacent to ports at Cordemais (2 × 600 MW) and Le Havre (600 MW). Both are owned by EDF which plans to close the Le Havre plant in spring 2021 and convert the Cordemais plant to biomass by spring 2022. In July 2019, UNIPER announced the sale to EPH of all its assets in France, including the 600 MW Émile-Huchet unit 6 at Saint-Avold in Lorraine and the 600 MW Gardanne unit 5 in Provence, as well as a 150 MW unit converted to biomass known as “Provence 4 Biomasse” which was initially commissioned in 2017, but has run only intermittently since then. There are also three 100 MW coal-fired power plants in French overseas territories: one in Guadeloupe and two in Réunion. During sugar campaigns, these plants also use renewable bagasse.
The French steel industry consumes important volumes of coal – around 4.5 million tonnes for coke making and 3.0 million tonnes at integrated steel works in 2018. ARCELORMITTAL plants at Dunkerque and Fos-sur-Mer are the biggest coal consumers in this sector.
Lying in the Caucasus region between Europe and Asia, Georgia has significant hard coal reserves of 201 million tonnes plus resources of 700 million tonnes in the Tkibuli-Shaori and Tkvarcheli deposits. The Akhaltsikhe lignite deposit near Vale has reserves of 76 million tonnes, currently not exploited. Coal production in Georgia peaked at 3 million tonnes in 1958, but by 2000 production had collapsed to almost zero. Following the “Rose Revolution” of 2003 and conflict with Russia in 2008, the coal industry was revitalised. In 2018, Georgia produced 219 thousand tonnes of coal from mines at Tkibuli and imported 145 thousand tonnes of coal mainly for industrial use.
Coal provided 6.2% of Georgia’s total primary energy supply of 6.8 million tonnes of coal equivalent in 2017. Fossil gas is the main primary energy source (41.4%), followed by oil (27.5%), hydro (16.7%) and biomass (7.7%). Wood consumption, mainly for space heating, water heating and cooking, has led to deforestation problems. Hydro power plants are the most important source of electricity, producing 79.9% of the 11.5 TWh total in 2017. Thermal power plants fired on imported fossil gas from Russia and Azerbaijan accounted for 19.1%. Coal and wind power were insignificant, but electricity imports added 1.5 TWh to supply in 2017. There is potential to expand hydro and wind power generation for export. To this end, the 2 x 350 MW Black Sea Transmission Network HVDC link with Turkey was completed in December 2013 with support from the European Investment Bank and the German government.
SAKNAKHSHIRI or Georgian Coal, a subsidiary of the GEORGIAN INDUSTRIAL GROUP (GIG), owns and operates the underground coal mines Dzidziguri and Mindeli in the city of Tkibuli, the only coal mines in Georgia. These mines supply cement works at Kaspi and Rustavi as well as the ferroalloy industry. The mines employed 1 400 workers, but mining was suspended following a fatal accident in July 2018. With GIG’s license covering more than 331 million tonnes of resources, the Tkibuli coal mining development plan envisages raising output to 550 thousand tonnes per year once safety issues have been addressed by a new owner, the STEEL INTERNATIONAL TRADE COMPANY. GIG operates a small coal-fired power plant with a capacity of 13 MW at Tkibuli.
Coming Into force in July 2016, the Association Agreement between Georgia and the European Union includes a “deep and comprehensive free trade area”. The country is also a party to the Energy Community Treaty and, in May 2019, signed a co-operation agreement with the European Network of Transmission System operators for Electricity (ENTSO-E).
In the breakaway republic of Abkhazia, the Turkish operator TAMSAŞ produced good quality coal at an opencast mine in the Tkvarcheli coalfield until 2018 when the exploitation of deeper parts of the 20 million-tonne reserve became uneconomic. The coal terminal at Ochamchire port has been greatly expanded over recent years to handle transhipments.
In recent years, the Irish economy has made a strong return to growth, following the sharp economic downturn that began with the 2008 global financial crisis. Energy use has grown, but is still below pre-crisis levels.
Ireland has no indigenous coal production, although 3.9 million tonnes of peat were harvested in 2018 for energy use, accounting for 16.0% of total indigenous energy production. Coal imports totalled 1.3 million tonnes in 2018, all steam coal and mostly from Colombia. Coal and peat use have declined and together accounted for 10.3% of Ireland’s total primary energy supply in 2018 which was 19.7 million tonnes of coal equivalent. They are used mainly for power generation.
BORD NA MÓNA is the leading peat producer and distributes solid fuel products within the residential heating market in Ireland. The company’s peat briquettes are popular due to their low sulphur emissions and competitive price. BORD NA MÓNA plans to end all of its peat harvesting operations by 2027.
Since 2001, peat-fired power plants were supported by a public service obligation as, with their use of indigenous fuel, they contribute to security of electricity supply. However, this support expired in 2015 in the case of the Edenderry power plant and in 2019 in the cases of the West Offaly and Lough Ree plants. In addition, the government has set a 30% biomass dilution target for peat used as a fuel. For example, the 128 MW Edenderry power plant was designed and built to fire peat, but is now co‑fired with a mixture of peat and biomass from forests and energy crops. The use of biomass commenced in 2008 and has increased steadily. In 2018, 6.8% of Irish electricity was generated from peat and 1.1% from biomass.
Ireland has one coal-fired power plant, at Moneypoint in County Clare operated by the ELECTRICITY SUPPLY BOARD (ESB). At 915 MW, it is Ireland’s largest power station, having been fully commissioned in 1987 as part of a fuel diversification strategy. Significant refurbishments have been carried out by ESB to meet environmental standards, including a €368 million investment in pollution control equipment to meet EU regulations on NOx and SO2. Moneypoint is expected to operate until 2025. Indeed, the Irish government’s policy is to cease using coal for electricity generation by 2025 and peat by 2030.
Fossil gas was the dominant fuel for power generation in 2018 with a 51.8% share of generation, followed by wind (27.3%) and coal (7.0%). The Corrib offshore gasfield came onstream in late 2015, adding 3.6 million tonnes of coal equivalent to Irish energy production in 2018 and reducing the country’s gas import dependency to 38.8%. Overall, Ireland had an import dependency of 63.8% in 2018, excluding aviation and marine bunkers, compared with an EU average of around 55%.
Although a single electricity market covers the Republic of Ireland and Northern Ireland, and a 500 MW interconnector links this to the UK mainland, the island market is quite isolated. With wind power generation growing strongly (22% per year since 2000), the island grid increasingly relies on conventional power plants during periods of low wind and high demand. To ensure sufficient dispatchable capacity, the first auction under a capacity remuneration mechanism (CRM) was held in December 2017.
Italy has a very low demand for coal. In 2018, coal covered only 5.8% of primary energy supply which totalled 215.6 million tonnes of coal equivalent, this being 19.2% below its 2005 peak. Emissions of CO2 from fossil fuel use fell even more – by 31.1% since 2005 – as the Italian energy mix shifted towards fossil gas and renewable energy sources. Since 1990, Italy’s greenhouse gas (GHG) emissions have fallen by almost 20%.
The only coal reserves and resources in Italy are located in the Sulcis-Iglesiente basin, in south-west Sardinia, totalling an estimated 610 million tonnes. Mining activities were stopped there in 1972, but restarted in 1997 with many environmental improvements. Saleable production in 2018 was an estimated 243 tonnes, although for economic reasons this was left underground. In accordance with EU state-aid law, CARBOSULCIS, owned by the Regional Government of Sardinia, closed Monte Sinni mine at Nuraxi Figus in December 2018. The agreed closure plan foresees work on safety and environmental restoration, renewable energy projects and research activities aimed at the industrial redevelopment of the site though to 2027.
Italian electricity production is uniquely fragile, with no solid baseload nuclear or coal power. On average, G7 countries rely on coal and nuclear for 43.8% of their power generation. In Italy, the comparable figure is just 10.5%, all from coal. This means an overdependence on fossil gas which accounted for 44.6% of gross power generation in 2018, followed by hydro (17.0%), solar (7.8%), wind (6.0%) and oil (3.7%). Biofuels, energy from waste and geothermal accounted for the balancing 10% of electricity production. After growing strongly under five Conto Energia schemes which ended in 2013 and other green subsidies, the share of new renewables (solar, wind and biofuels) stagnated over the five-year period to 2018 at around 20%. Net electricity imports of 43.9 TWh in 2018 met over 13% of gross electricity supply.
In a decisive June 2011 referendum, Italian voters rejected government proposals to restart a nuclear programme that was abandoned following an earlier referendum held after the 1986 Chernobyl disaster.
Italy had an overall energy import dependence of 77.0% in 2017, rising to 92.3% in the case of fossil gas. In 2018, fossil gas imports came mainly from Russia (48%), Algeria (27%) and Qatar (10%). Italy also imported 10.8 million tonnes of steam coal in 2018 and 3.3 million tonnes of coking coal, the latter including PCI coal. The main supply countries were Russia, the United States and Colombia. In October 2017, ENEL sold its 10% shareholding in PT BAYAN RESOURCES of Indonesia which produced 20.9 million tonnes of coal in 2017 and 28.9 million tonnes in 2018. Coal imports into Italy peaked in 2008 at 25.1 million tonnes and have since fallen because of the forced closure of the 660 MW Vado Ligure coal-fired power plant owned by TIRRENO POWER, the closure of a further three coal power plants (Brindisi Nord, Genoa and “Pietro Vannucci” Bastardo in Umbria) and ongoing difficulties at the ARCELORMITTAL steel plant in Taranto.
Mainland Italy now has just six coal-fired power plants: ENEL Torrevaldaliga Nord on the coast near Rome (1 320 MW), ENEL Andrea Palladio-Fusina near Venice (960 MW), ENEL Brindisi Sud “Federico II” (2 640 MW), A2A Monfalcone (336 MW), ENEL “Eugenio Montale” at La Spezia (600 MW) and A2A Brescia (70 MW).
Following their modernisation and conversion from fuel oil to coal, Italy has some of the best-performing coal-fired power plants in Europe. The Torrevaldaliga Nord power plant attains a net efficiency of 45%, thus matching the world-leading performance of plants in Japan. It is estimated that, by 2038, all the modernisation investments at Italian coal power plants will have been fully amortised. However, Italy’s coal-fired power plants are destined to reduce their output and close before then.
On 8 January 2019, the Italian government presented to the European Commission its draft Integrated National Energy and Climate Plan (PNIEC). In it, great emphasis is placed on an acceleration of decarbonisation policies and the promotion of renewable energy sources as part of an economy-wide transformation. For coal, the plan confirms what was proposed in the National Energy Strategy of 2013, i.e. the closure of all Italian coal-fired power plants by 2025.
To protect the competitiveness and security of the Italian power system, the planned coal phase-out is to be gradual and closely connected to power plant replacement and extension of power transmission, distribution and energy storage infrastructure. However, without nuclear and coal, and with the emphasis on more expensive renewables, Italy faces an uncompetitive power generation mix that will contribute to weaker industrial activity and higher electricity prices for households. The closure of coal plants will exclusively benefit oligopolistic gas producers, such as GAZPROM, the largest Russian company, and SONATRACH, the Algerian state-owned oil company.
Absent appropriate actions, there are serious issues with the coal phase-out plan. For example, the closure of the two coal-fired power plants on Sardinia (640 MW EPH Fiumesanto and 340 MW ENEL Sulcis “Grazia Deledda”) appears to be technically impossible as they account for 70% of the island’s power production. The same situation affects Italy’s central-northern grid which already experiences security and adequacy problems.
Moreover, from an environmental point of view, in a world where coal will continue to be used for power generation, the coal phase-out plan will be of little climatic benefit as the CO2 emissions from coal-fired power generation in Italy accounted for just 0.06% of global GHG emissions in 2018.
In 1952, when its prosperity was based on steelmaking, the Grand Duchy of Luxembourg was chosen as the site of the European Coal and Steel Community, marking the start of the institutional development that led to the European Union. Luxembourg continues to enjoy strong economic growth, of over 2.5% per year, and a growing population.
With an energy-import dependence of 95%, Luxembourg is among the most import-dependent EU member states, after Malta and Cyprus. The country has only one major power generation site: the RWE-operated 1 300 MW pumped-storage hydro plant at Vianden. A 385 MW combined-cycle gas turbine plant at Esch-sur-Alzette operated by TWINERG was prematurely closed in 2016 for economic reasons. Luxembourg thus generates only one quarter of its electricity needs (excluding pumped hydro) and imports the rest, mainly from Germany. It is part of the DE/AT/LU bidding zone and, since October 2017, the BeDeLux interconnector between Belgium, Germany and Luxembourg has been in operation, while a new DeLux interconnector is planned.
The steel industry’s conversion to electric-arc furnaces (ARCELORMITTAL steel works at Esch-Belval and Differdange) has practically eliminated Luxembourg’s coal use and means the sector accounts for around 40% of total electricity demand. Coal is used today mainly for the production of cement at the CIMALUX Rumelange plant. All coal is imported – 63 thousand tonnes in 2018 – and makes only a small contribution to the country’s primary energy supply. Yet, in 2017, Luxembourg had the highest per capita greenhouse gas emissions by far (20.2 tCO2e/capita) of all the EU member states.
Malta has no conventional energy production and reports no coal consumption. Until 1995, coal was imported for power generation. The inefficient 90 MW Marsa and 444 MW Delimara 1 power plants, both running on heavy fuel oil, were decommissioned in 2015 and 2017 respectively. To replace them, ENEMALTA PLC built Delimara 4 – a 205 MW combined cycle gas turbine plant supplied from a floating LNG import facility. In addition, the 153 MW Delimara 3 power plant, commissioned in 2012 and comprising eight diesel engines and a steam turbine, has been converted to run on fossil gas. For security of supply reasons, four engines can also run on diesel oil. A 120-kilometre 200 MW interconnector to Sicily was commissioned in 2015.
The Republic of Moldova does not produce coal or lignite. It imports small quantities of hard coal for use by industry and in heating plants – 142 thousand tonnes in 2018. Coal represents less than 3% of gross inland energy consumption.
Electricity is imported from Ukraine, but mostly from the 2 520 MW Kuchurgan thermal power plant located on the shores of Cuciurgan reservoir in the Transnistria region. This twelve-unit plant can run on coal, fossil gas or fuel oil. In 1990, over 4 million tonnes of coal were consumed there, but since the late 1990s the station has used virtually no coal. Although the Moldovan electricity grid is synchronised with Russia’s (IPS/UPS), some units at Kuchurgan could be synchronised with Continental Europe to allow exports of electricity via Romania. Owned by MOLDAVSKAYA GRES, a subsidiary of the Russian company INTER RAO UES, the plant is in need of further refurbishment and only operated at 17.8% of its installed capacity in 2018.
The remaining supply of electricity is covered by two gas-fired combined heat and power (CHP) plants in Chisinau (64 MW + 240 MW), a 20 MW CHP plant in Balti, ten CHP plants at sugar refineries (totalling 98 MW) and two hydro power plants: the 48 MW Dubăsari plant and another 16 MW plant at Costesti.
Hard coal mining dominated the South Limburg area of the Netherlands from the late 19th century to the mid-1970s. The coalfield, located in the south of the country close to the German and Belgian borders, was mainly exploited from underground mines. Coal mining in the Netherlands ended in 1974 when the private Oranje-Nassau Mine I and Julia coal mines closed. Emma mine, the last state-owned mine, was closed in 1973.
Since around 1915, lignite was extracted at opencast mines near the towns of Eygelshoven and Hoensbroek. The deposits are located on the north-west fringe of the large Rhenish lignite basin to the west of Cologne in Germany. Lignite mining ended in 1968 with the closure of the Carisborg site.
The Netherlands is home to the main ports for the transhipment of coal imports into Europe. The ports at Amsterdam and Rotterdam, along with Antwerp port in Belgium, together make up the ARA trading area for imported steam coal and coking coal in north-west Europe.
In 2018, 11.3% of the Netherlands’ primary energy supply was provided by coal, all imported. The country imported 13.0 million tonnes in 2018, comprising 8.8 million tonnes of steam coal and 4.2 million tonnes of coking coal. The main supplier countries were Russia, the United States, Australia and Colombia.
Most imported coal is used for coal-fired power generation: coal had a 26.3% share of the 113.5 TWh gross electricity generation in 2018, including the use of coke oven gas and blast furnace gas at steelworks. The fleet of Dutch coal power plants is very modern and includes: UNIPER 1 070 MW Maasvlakte 3 plant in the Rotterdam area, ENGIE 800 MW Maasvlakte plant, commissioned in early 2015, and RWE 1 560 MW Eemshaven plant near Groningen. All three of these plants employ the latest supercritical steam technologies to achieve high energy efficiencies. Older coal-fired plants operate at Geertruidenberg (600 MW Amer) and Amsterdam (630 MW Hemweg 8). Some plants co-fire coal with biomass, to a greater or lesser extent. Ownership is very diverse, with ESSENT (a subsidiary of RWE), ELECTRABEL (a subsidiary of ENGIE), UNIPER and NUON (a subsidiary of VATTENFALL) being the major players in coal-fired power generation.
Under the Climate Act of 2018, the Netherlands has committed to reduce its greenhouse gas emissions by 49% by 2030 and by 95% by 2050, compared with 1990 levels. In its Climate Agreement of June 2019, the national coalition government agreed to phase out coal-fired electricity generation by 2025/2030, with the first plant to be closed by 2020 and the three modern plants at the beginning of 2030. The government will introduce a targeted carbon levy on industry, starting at €30 per tonne of CO2 in 2021 and rising to €125-€150 per tonne in 2030, including the EU ETS allowance price, on emissions that exceed a fixed reduction path. A minimum CO2 price for electricity production will also be introduced.
In response to these political developments, ENGIE agreed the sale in April 2019 of its Maasvlakte and other plants to RIVERSTONE HOLDINGS of the United States for an average of €85 per kilowatt (compared with Maasvlakte’s investment cost of €1 500 per kilowatt in 2009). In the case of NUON, the Dutch government has ordered the company to close Hemweg 8 by the end of 2019. Meanwhile, RWE will convert its Eemshaven plant to co-fire biomass.
The Dutch government has supported CCS demonstration projects, including the ROAD project (Rotterdam Opslag en Afvang Demonstratieproject). Under the Climate Agreement, subsidies will be offered to CO2-reducing options in industry, such as CCUS.
TATA STEEL owns the IJmuiden integrated steel works which has a crude steel annual production capacity of 7 million tonnes and consumes most of the coking and PCI coal imported by the Netherlands. A pilot project at IJmuiden to demonstrate the Hisarna iron-making process aims to reduce CO2 emissions from steelmaking.
Norway, Europe’s northernmost country, opted to stay out of the European Union by referendum in 1994, but supplies significant volumes of oil and fossil gas to the Union. In 2017, 25.3% of EU gas imports came from Norway which is the world’s third largest gas exporter after Russia and Qatar. Hydro power plants supplied 95.0% of Norway’s gross electricity generation in 2018 and the country is a significant net exporter of electricity: 6.9% of gross production.
In 2018, Norway produced 145 thousand tonnes of hard coal and imported 746 thousand tonnes of steam coal for use in the metallurgical industry, chemicals production and cement manufacture. 113 thousand tonnes of steam coal were exported in 2018.
Norway has access to deposits of good quality, high calorific value coal at Svalbard lying within the Arctic Circle where resources are estimated to total 90 million tonnes, with reserves of 1.0 million tonnes.
Coal mining on Spitsbergen, the largest and only permanently populated island of the Svalbard archipelago, has served multiple government goals, not all related to energy. Without continued peaceful economic activity on Spitsbergen, Norwegian sovereignty might be weakened by foreign economic activity as the Svalbard Treaty of 1920 grants rights to all thirty-nine signatories. The state-owned STORE NORSKE SPITSBERGEN KULKOMPANI (SNSK) was established in November 1916 and owns three drift mines employing 124 people: Svea Nord longwall mine located 60 kilometres south of Longyearbyen, Lunckefjell mine north-east of Svea, and Gruve 7 room-and-pillar mine in the valley of Adventdalen near Longyearbyen. There is no road connection between Longyearbyen and Svea, so all personnel transport is by plane or snowmobile in the winter. Spitsbergen’s 10 MW coal-fired combined heat and power plant takes coal from Gruve 7 and a decision must be taken soon on its replacement. At NOK 3-5 billion, an underwater cable from the mainland is possible, but very expensive.
Political guidance for SNSK’s operations is laid down in a government White Paper (No. 22 to the Storting, 2008-2009), establishing that SNSK and its coal mining operations are – and will remain – important for maintaining a Norwegian community in Longyearbyen on Spitsbergen.
The majority of coal production in the past was carried out in Longyearbyen. From 2000 until 2015, the principal activities of SNSK were located at Svea. In 2007, total coal production on Spitsbergen was 4.0 million tonnes. However, mining at Svea Nord and preparatory works on the new mine at Lunckefjell were put on hold by the Norwegian government in January 2015 as low coal prices had led to a difficult economic situation. Extensive cost reductions and a significant downsizing of SNSK continued in 2016. To bring in some revenue from tourists, Gruve 3 which closed in 1996 re‑opened as a museum with underground tours.
In 2017, the Norwegian government decided to permanently stop coal mining activities at Svea and Lunckefjell. The area has to be cleared and all the mining equipment is to be sold. This process will take several years and equipment will be sold as it becomes available.
In the future, the only mining will be at Gruve 7, directed by STORE NORSKE GRUVEDRIFT AS, with annual coal production of around 140 thousand tonnes.
In co‑operation with SINTEF and the Arctic University of Norway, SNSK has been engaged in research projects supported by the Norwegian Research Council on alternative uses for coal and processed coal with the aim of increasing the value of Svalbard coal.
Norwegians are conscious that end-use emissions from the country’s exports of oil and gas are substantial. In response, Norway has been a pioneer in the field of carbon capture and storage: at the Sleipner gasfield and at the Snøhvit LNG project. The CO2 Technology Centre Mongstad was inaugurated in May 2012 to develop CO2 capture technologies for both gas- and coal-fired power plants.
Portugal has limited indigenous energy resources, leading to a 79.9% energy-import dependence in 2017. Its last coal mine, Germunde in the Castelo de Paiva region, was closed in 1994, leaving behind national reserves of 3 million tonnes. The country also has lignite resources of 66 million tonnes.
In 2018, 51.1% of Portugal’s electricity production came from renewable energy sources: hydro, wind, biofuels, solar PV, geothermal and wave. Nevertheless, conventional thermal power generation remains crucial to cover those periods when wind power is not available and to balance the annual variations in hydro power production on the Iberian Peninsula. Coal-, oil- and gas-fired power generation together accounted for 48.0% of gross electricity production in 2018. Coal’s share of gross production was 20.2%.
Imported coal accounted for 12.4% of total primary energy supply in 2018 with imports of 4.7 million tonnes coming from Colombia and the United States. Most of this coal was consumed at Portugal’s two coal-fired power plants located at Sines (1 256 MW) and Pego (628 MW). Both are fitted with flue gas desulphurisation and selective catalytic reduction to reduce emissions of sulphur dioxide and NOx.
Sines power plant, adjacent to a coal import terminal on the Atlantic coast, was built in the late 1980s and is owned by ENERGIAS DE PORTUGAL (EDP). The inland Pego power plant, about 120 kilometres north-west of Lisbon, was fully commissioned in 1995 and is now owned by TRUST ENERGY, a 50%-50% joint venture between ENGIE and MARUBENI. Around 650 are employed at the two power plants and the coal port.
In November 2017, the Portuguese Government announced its commitment to retire all coal-fired power plants by 2030. Since 1 January 2018, coal used to produce electricity in Portugal has been taxed at a rate corresponding to 10% of the tax on petroleum and energy products, plus a carbon tax corresponding to 10% of the additional levy on CO2 emissions. These rates will be increased each year to reach 100% in 2022.
South East Europe
The countries of South East Europe not covered in earlier chapters include Albania, Bosnia and Herzegovina, Croatia, Kosovo, North Macedonia and Montenegro.
Albania produces very small volumes of lignite, about 296 thousand tonnes in 2018, and imports further volumes to meet demand totalling an estimated 430 thousand tonnes at industrial and residential customers, including the Antea cement works. With total resources of 727 million tonnes, the country has the potential to support a much larger coal mining industry. During the 1980s, annual coal production of around 2.4 million tonnes came from mines in central Albania: at Valias, Manëz and Krrabë; at Mborje and Drenovë in the Korçë district; in northern Tepelenë at Memaliaj; and at Alarup to the south of Lake Ohrid.
The country produces all of its electricity at hydro plants with a total capacity of 2.1 GW. A 98 MW gas- / oil-fired thermal power plant at Vlorë is currently inoperable. Imported electricity covers around 40% of total electricity supply.
The Trans-Adriatic Pipeline (TAP), which will deliver Azeri gas via Greece and Albania to Europe, is expected to create a demand for fossil gas in Albania. Construction of the TAP is scheduled to finish in 2019, with first gas deliveries to Italy expected in 2020.
In Bosnia and Herzegovina, brown coal and lignite make a very large contribution to primary energy supply (62.0% in 2017). Only North Korea, South Africa, Mongolia and China have higher coal dependencies. In 2018, Bosnia and Herzegovina produced 14.3 million tonnes of brown coal and lignite. This was mostly used to generate electricity at power plants near to coal mines: 73.0% of the country’s gross electricity production was from coal in 2017. In addition, 1.5 million tonnes of imported coking coal was consumed in 2018.
At 2 264 million tonnes, Bosnia and Herzegovina’s reserves of lignite are substantial. Total lignite resources are reported to be 5 274 million tonnes. The largest coal deposits are located in the north-east of the country around Tuzla in the Kreka-Banovići coal basin. Bosnian lignite typically has a lower calorific value of 9 100 kJ/kg (2 200 kcal/kg), a moisture content of 49%, an ash content of 3.8% and a high sulphur content (as-received values).
ELEKTROPRIVREDA BOSNE i HERCEGOVINE (EPBiH) is a state-owned utility company with seven subsidiary coal mining companies: Rudnici „Kreka“ (Šikulje and Dubrave opencast lignite mines and Mramor underground mine); RMU „Kakanj“ (Vrtlište opencast mine, Haljinići underground mine and Begići-Bištrani underground mine which opened in July 2013); RMU „Zenica“ (Stara Jama, Raspotočje and Stranjani underground mines); RMU „Breza“ (underground mines at Sretno and Kamenice); RMU „Đurđevik“ (Višća opencast brown coal mine and Đurđevik underground mine); and RMU „Abid Lolić“ and RU „Gračanica“ which operate opencast mines.
RMU BANOVIĆI operates two large opencast mines at Grivice and Turija, employing hydraulic shovels, draglines and 170‑tonne trucks to mine a 12-metre seam. The Čubrić opencast mine was closed in 2011. Opencast mines at Banovići have an average overburden ratio of 5 cubic metres per tonne. The company also operates the partly mechanised Omazići underground coal mine. In November 2015, RMU BANOVIĆI signed an agreement with DONGFANG ELECTRIC CORPORATION of China to build a new power plant in Banovići. Financed by the INDUSTRIAL AND COMMERCIAL BANK OF CHINA, the €400 million project includes a 350 MW lignite-fired unit with a supercritical circulating fluidised bed boiler. In September 2019, IGH of Croatia, STEAG ENERGY SERVICE and SGS were selected to supervise the power plant construction project.
Coal mines situated in northeast and central Bosnia serve the Tuzla and Kakanj power plants owned and operated by EPBiH. The Gacko coal mine and power plant in the south of the country as well as the Bogutovo Selo opencast mine and Ugljevik power plant in the east are operated by the state-owned ELEKTROPRIVREDA REPUBLIKE SRPSKE (EPRS). Other mines include Kamengrad mine and the Livno and Tušnica mines which supply Ugljevik power plant, although not all are in production.
The 715 MW Tuzla power plant has three operational units and supplies heat to Tuzla and Lukavac as well as process steam to nearby industries and fly ash to the cement works at Lukavac. After the Bosnian war of 1992-95, major overhauls were completed at the plant, including boiler upgrades and the installation of new electrostatic precipitators. The 450 MW Kakanj power plant has three units and was similarly reconstructed and modernised after the war. In addition to the generation of electricity, the power plant supplies heat to the city of Kakanj as well as ash and slag to the Kakanj cement works. New units are planned at both plants: the 450 MW Tuzla 7 and the 300 MW Kakanj 8.
In November 2017, EPBiH signed a loan agreement with the EXPORT-IMPORT BANK OF CHINA to finance the €722 million Tuzla 7 project. The new unit will replace the four oldest units at Tuzla (2 × 32 MW, 100 MW and 200 MW). When completed, Tuzla 7 will provide almost one quarter of EPBiH electricity production.
At the end of 2018, EPBiH adopted its 2019-2021 business plan in which construction of Tuzla 7 was given priority, followed later by Kakanj 8. These permitted power plants are needed to replace old units that must be phased-out due to limits imposed under EU regulations and also to provide a market for local coal.
The Gacko and Ugljevik power plants, each of 300 MW, were commissioned in 1983 and 1985 respectively. In 2019, MITSUBISHI HITACHI POWER SYSTEMS and RUDIS of Slovenia completed a FGD retrofit project at Ugljevik power plant. Under a national emission reduction plan (NERP) agreed with the Energy Community, FGD at the Gacko plant will be needed from 2023. In the future, lignite for these plants could come from new opencast mines being developed by COMSAR ENERGY at Delići, Peljave-Tobut and Baljak and by EPRS subsidiary RUDNIK i TERMOELEKTRANA (RiTE) UGLJEVIK at Ugljevik-Istok.
A new 300 MW lignite-fired power plant came online in September 2016 at Stanari in northern Bosnia and Herzegovina. The plant was built by DONGFANG ELECTRIC CORPORATION and financed by the CHINA DEVELOPMENT BANK with a €350 million loan. To supply the power plant, Stanari coal mine at Doboj, with reserves of 108 million tonnes, has increased its annual output capacity from 0.6 million tonnes to 2 million tonnes with a loan from SBERBANK of Russia. The UK-registered EFT GROUP owns the Stanari mine and power plant.
Croatia became the newest member state of the European Union on 1 July 2013. The country does not produce coal, but consumed 595 thousand tonnes of imported coal in 2018, mainly at the 335 MW Plomin I and II power plant which is 100% owned by HRVATSKA ELEKTROPRIVREDA (HEP). Coal accounted for 9% of total generation in 2017. In February 2018, HEP applied for a permit to modernise the 125 MW Plomin I unit to extend its life by 15-20 years. Plans for a third 500 MW unit at Plomin were cancelled in 2016.
Kosovo is governed by the United Nations Interim Administration Mission in Kosovo (UNMIK), following the violent conflict of 1996-99. It has very large lignite resources, totalling 10.8 billion tonnes and fourth only to Poland, Germany and Serbia in Europe. Reserves are located in the Kosova, Dukagjini, Drenica and Skenderaj basins, although mining has been limited to the Kosova basin to date. Lignite production in 2018 was 7.2 million tonnes.
For electricity, Kosovo was 93.2% dependent on lignite in 2017, with the rest coming from hydro plants and imports, including from a 32 MW hydro plant at Ujman/Gazivoda and other smaller plants.
The state-owned KORPORATA ENERGJETIKE e KOSOVËS (KEK) has a monopoly position in lignite mining and electricity generation. The Kosova A (comprising five units of which the 200 MW unit A3 and 2 × 210 MW units A4 and A5 are operational) and Kosova B (2 × 339 MW units) power plants near Pristina are supplied with lignite from Sibovc Southwest mine near Obilić which opened in 2010.
In December 2014, a successful bid for the new 500 MW “Kosova e Re” thermal power plant (a.k.a. Kosovo C) was submitted by CONTOUR GLOBAL of the United States to the Kosovan Ministry of Economic Development. This €1.2 billion project will replace Kosova A and will, with the development of the Sibovc mine, create 10 000 jobs, improve the environment and end the electricity blackouts that plague the country. In May 2019, GENERAL ELECTRIC was chosen to build Kosovo C with construction expected to start late in 2019.
North Macedonia is a significant lignite producer: 5.0 million tonnes in 2018 from the Suvodol and Oslomej surface mines of state-owned ELEKTRANI NA SEVERNA MAKEDONIJA (ESM) and a number of smaller, privately owned surface mines. Coal resources are estimated at 632 million tonnes in the Pelagonija and Kicevo basins, including deposits at Suvodol, Brod-Gneotino, Zhivojno, Oslomej, Popovjani and Stragomiste. Lignite from the Mariovo basin may be exploited to fuel a proposed new 300 MW power plant at Mariovo. In Mach 2019, tenders were invited for a 10 MW solar PV farm at the Oslomej mine.
Most coal and lignite is used for power generation which accounted for 54.0% of gross generation in 2017, mainly at the 675 MW ESM Bitola and 125 MW ESM Oslomej power plants. The balance is used almost entirely by the steel industry, including the DOJRAN STEEL plant at Nikolic, DUFERCO MAKSTIL’s integrated steel works at Skopje, and ARCELORMITTAL’s steel mill, also at Skopje.
Montenegro produced and consumed 1.6 million tonnes of lignite in 2018, mostly for power generation – 1.4 TWh in 2017, this being 54.8% of gross generation. Hydro power supplied 41.1% with the remainder coming from wind and solar PV. Although not currently exploited, Montenegro has hard coal resources of 337 million tonnes.
Montenegro’s 225 MW Pljevlja coal-fired power plant, commissioned in 1982 and owned by the majority state-owned company ELEKTROPRIVREDA CRNE GORE (EPCG), is supplied with brown coal (10 300 kJ/kg) from two surface mines operated by RUDNIK UGLJA PLJEVLJA employing 861, including contractors, and 100% owned by EPCG since June 2018. Under an agreement with the Energy Community on implementation of EU law, the unit may operate for 20 000 hours over the period 2018-2024. In March 2019, a contract was placed with STEAG ENERGY SERVICES of Germany to further upgrade the unit with flue gas desulphurisation and deNOx to meet the latest EU emission standards and thus extend the operational life of the plant. A heat offtake for district heating in Pljevlja is included in the upgrade. Earlier plans to construct a new unit have been put on hold and a contract with SKODA PRAHA for a new 254 MW unit was terminated at the end of 2017.
In 2014, METALFER acquired an underground coal mine at Berane which had been flooded and idle since 2005. Exploitable reserves are estimated at over 50 million tonnes of brown coal with a calorific value of 14 000-17 000 kJ/kg. In January 2015, commercial mining restarted at a depth of 200 metres, employing 140 people. Production in 2018 was 56 448 tonnes.
There is currently no coal mining in Sweden and imported coal accounted for only 4.6% of the country’s primary energy supply in 2018. Coal reserves and resources are estimated at 5 million tonnes in southern Sweden. In 2018, 540 thousand tonnes of peat were extracted.
Since the mid-1990s, coal imports have been stable at close to 3 million tonnes per year (2.7 million tonnes in 2018). Demand for high-quality coking coal from Australia and the United States comes mainly from Sweden’s speciality steel industry. Limited quantities of steam coal, mostly imported from Russia, are used at cement works and at combined heat and power plants which are fuelled mainly with solid biofuels, including at the FORTUM / STOCKHOLM EXERGI Värtan plant in Stockholm. Coal was used in the pulp and paper industry, but has been replaced with biofuels.
In 2018, nuclear power accounted for 41.3% of Sweden’s gross electricity production, while the share of hydro power was 38.7%. The balance was met by wind power (10.4%) and CHP plants firing mainly solid biofuels and wastes (7.5%), and fossil fuels (1.9%). Wind and biomass are generously subsidised while nuclear and fossil fuels are heavily taxed.
The role of nuclear power has long been the subject of political debate in Sweden. In June 2010, the parliament agreed that new nuclear power plants could replace old ones at existing sites. After lengthy negotiations, this policy was restated in a cross-party framework agreement of June 2016.
A new Climate Act entered into force on 1 January 2018 with the aim of linking Sweden’s annual Budget Bill with climate objectives. An independent climate policy council will hold the government to account. In June 2018, the Energy Bill adopted by parliament includes a 100% target for renewable electricity production by 2040. In response to such political developments, the owners of the Värtan CHP plant have decided to phase out coal use by 2022.