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Energy supply Uzbekistan is one of the world’s largest natural gas producers. Its energy production amounted to 54.5 million tonnes of oil equivalent (Mtoe) in 2019. Energy production reached a record high of 56.7 Mtoe in 2008. This amount had decreased by 20% by 2015, mainly due to the global economic crisis and a decline in natural gas reserves. It then recovered by 22% by 2019 from the 2015 level thanks to the development of gas projects in Uzbekistan. Natural gas is the dominant energy source in Uzbekistan, accounting for 90.5% of total energy production (49.3 Mtoe in 2019), while other energy sources include oil (5.8% in the same year), coal (2.6%), hydro (1.0%) and a negligible amount of biofuels (Figure 1).
Policy landscape for renewables in Uzbekistan To ensure energy security and promote renewable energy use, the government of Uzbekistan has adopted a wide range of strategies and laws related to energy. The Strategy of Action for the Five Priority Development Areas of Uzbekistan in 2017-2021, adopted in February 2017, provides key directions for economic development. In terms of energy, the strategy indicates the need for reducing the energy intensity and resource intensity of the economy, the widespread introduction of energy-saving technologies in production, and expanding the use of renewable energy sources. The government expects the share of renewable generation in the power mix to increase to at least 20% by 2025 (compared to 9.4% in 2018), as indicated in the Strategy for Innovative Development of the Republic of Uzbekistan for 2019- 2021, adopted in September 2018. Building reliable electricity networks is essential for the deployment of more renewables in the power sector. In this regard, the Strategy for the Development of Electric Networks in the Republic of Uzbekistan until 2025 was formulated in July 2019 It provides an overall plan for the construction of new and the modernisation of existing transmission and distribution lines and substations up to 2025
The National Dispatch Centre under NEGU is in charge of dispatching all power plants in accordance with the Rules for the Production, Transmission and Distribution of Electrical Energy approved by the Cabinet of Ministers. Both NEGU and territorial JSCs under the Regional Electric Power Networks JSC are responsible for electricity transmission and distribution, respectively. The TPPs and some HPPs with reservoirs provide flexibility to the power system, and are dispatched depending on electricity demand. Business entities such as independent power producers are guaranteed connection to the energy system, including electricity and thermal, and contract with NEGU to supply energy produced from renewable energy sources; the cost of connecting to the energy system, including grid enhancement, is mainly borne by the entities. The technical procedure of the grid connection, including non-discriminatory access to the system for the business entities, is defined by the Regulation for Connecting Businesses that Produce Electricity, Including from Renewable Energy Sources, to the Unified Electric Power System, approved in July 2019.
Solar PV-to-heat (PV2heat) for domestic hot water PV2heat systems are becoming increasingly popular in several regions of the world, especially for domestic hot water. These systems consist of PV modules directly and solely connected to an electrical element that heats the water with DC power, without the need for inverters. Some systems also usually include an AC element connected to the electricity grid to heat the water when the sun is not shining (IEA SHC TCP, 2021a). PV2heat systems benefit from a simple installation, only requiring wiring from the panels to the water tank instead of insulated pipes, as is the case with traditional solar water heaters. They can also be integrated into existing water tanks. In comparison with traditional solar thermal, PV2heat systems can be particularly relevant in areas with lower insolation and colder temperatures. One downside of the simplicity of this installation is that it is also at higher risk of theft in some areas.
Conclusion Uzbekistan has abundant renewable energy potential, most of which lies in solar energy thanks to high solar irradiation. However, until now energy supply has been dominated by fossil fuels, with renewable energy – almost exclusively hydropower – accounting for only 1% of its total energy production in 2019. To satisfy growing energy demand while promoting renewable energy use, the government of Uzbekistan has adopted a wide range of energy strategies and laws and has been undertaking energy sector reform to increase solar energy use and make it a key energy source by 2030. These efforts could be complemented by: further exploring the potential of solar energy applications; establishing policy and regulatory frameworks to enable greater deployment of solar energy facilities; and increasing power system flexibility to address the variability of VRE generation. These aspects include phasing out inefficient fossil fuel subsidies while protecting economically vulnerable consumers, implementing tariff reform, and investing in upgrading and improving the capacity and reliability of the power transmission system. All of this would allow Uzbekistan to better integrate increasing amounts of solar energy through 2030.
Introduction The Southeast Asia Energy Outlook 2022 is the fifth edition of this World Energy Outlook Special Report. Building on its important partnership with Southeast Asia, the International Energy Agency (IEA) has published these studies on a regular basis since 2013. The studies offer insightful prospects for the ten member countries of the Association of Southeast Asian Nations (ASEAN) – Brunei Darussalam, Cambodia, Indonesia, Lao People’s Democratic Republic (Lao PDR), Malaysia, Myanmar, the Philippines, Singapore, Thailand and Viet Nam. Since the last edition of this report, the energy prospects for Southeast Asia have been affected by the Covid-19 pandemic, new energy and climate policy commitments and, most recently, high and volatile prices exacerbated by the Russian Federation’s (hereafter, “Russia”) invasion of Ukraine. Covid-19 led to a major economic shock for countries in Southeast Asia and the economic recovery now risks being slowed by higher energy prices. In the run up to the UN Climate Change Conference (COP26) in November 2021, several governments in Southeast Asia announced ambitious targets for reaching neutrality and curbing reliance on coal-fired power.
Southeast Asia must attract much higher levels of energy sector investment to accelerate its clean energy transition and meet the rising demand for energy services
Energy investment: attracting finance requires upgrading clean energy policy and regulatory frameworks and addressing a wide range of financial hurdles across the sectors Southeast Asia faces the twin challenges of increasing total investment in the energy sector while increasing the share of this investment going to clean energy technologies. Between 2016 and 2020, annual average energy investment in Southeast Asia was around USD 70 billion, of which around 40% went to clean energy technologies – mostly solar PV, wind and grids. Energy investment in the STEPS reaches an annual average of USD 130 billion by 2030 and in the SDS it reaches USD 190 billion. Improving regulatory and financing frameworks would help Southeast Asia reduce the costs of clean energy projects. For example, the levelised cost of energy (LCOE) of solar PV in Indonesia could be around 40% lower if its investment and financing risks were comparable to advanced economies. Boosting investment in clean energy technologies requires strengthening clean energy policy and regulatory frameworks and addressing a wide range of financial hurdles.
Power flexibility: growing deployment of wind and solar will require a more flexible power system – this must be a higher priority for governments and regulators
Southeast Asia is a major engine of global economic growth and energy demand Southeast Asia’s growing population and economy put its energy sector outlook firmly in the global spotlight. Its population has expanded by around 10% over the past 10 years and today there are around 660 million people across the region. Southeast Asia’s economy grew by around 4.2% on average each year between 2010 and 2019. Each of the 10 countries in ASEAN is distinctive in terms of its stage of development, industrial output, politics, history and geography. For example, energy demand per capita in Myanmar or Cambodia is about one quarter of the world average, while in Singapore it is about three times larger than the world average. Increases in manufacturing have been the driving force behind the economic development in Thailand and Malaysia, while the Philippines has seen much more growth in its service industry. Energy policy priorities also differ from country to country, with different approaches to securing new energy supplies to meet expanding energy demand, achieving climate goals and ensuring access to affordable, reliable and modern energy for all. Nonetheless, a common denominator is a commitment to regional cooperation as a way to secure future prosperity and security.
CO2 emissions: in the STEPS, emissions grow steadily to mid-century, while a trajectory consistent with the region’s declared ambitions would see a peak before 2030
Southeast Asia is still a long way off the pathway consistent with its clean energy ambitions Emissions of CO2 from the energy sector have increased steadily in Southeast Asia in recent years. Indeed, the pace of emissions growth has been higher than previously projected in our Outlook, despite the impact of the Covid-19 pandemic on energy use and emissions (see next pages). In the STEPS, emissions increase by slightly over 50 Mt CO2 each year to 2035. This maintains the average annual increase seen over the last ten years. The growth in emissions moderates slightly after 2035 as energy demand growth slows and as renewables provide an increasingly large share of the overall increase in energy demand, but there is no peak in emissions before 2050. Cumulative CO2 emissions between 2020 and 2050 in Southeast Asia total just under 75 Gt CO2 in the STEPS. Southeast Asia has relatively limited responsibility for historical energy-related emissions, accounting for 3% of the total over the past half century. Projected emissions to 2050 in the STEPS are equivalent to around 15% of the remaining global CO2 budget that is consistent with limiting the average temperature rise to 1.5 °C (with a probability of 50%); in 2050, Southeast Asia comprises around 8% of the world’s population and global GDP.
Energy imports: Southeast Asia faces huge payments and energy security challenges from rising fossil fuel imports, led by oil
Energy security concerns reinforce the case for rapid energy transitions Russia’s invasion of Ukraine has been a strong reminder of the importance of energy security. In the STEPS, rapidly growing fuel demands raise concerns about increasing the dependency on imports which could render the economy more vulnerable to fuel supply disruptions outside the region. In the SDS, import dependency is reduced, but this does not guarantee immunity from energy security hazards, including the risk of investment imbalances or bottlenecks in the availability of critical minerals (see next chapter). In the early 2000s, Southeast Asia was a net exporter of fossil fuels, but the cost of rising oil imports now more than offsets the revenue from exports of coal and gas. The average import bill over the past decade has stood at about USD 43 billion or 1.7% of GDP. In the STEPS, this vulnerability is exacerbated by rising imports, especially of oil. The energy import bill rises to about USD 190 billion by 2030, which is equivalent to almost 4% of the region’s GDP (and this assumes that oil and natural gas prices drop significantly from the very high levels seen in 2021 and so far in 2022). The import bill continues to rise after 2030, albeit at a slightly slower pace, but exceeds USD 300 billion by 2050. In the SDS, the import bill is considerably smaller, peaking at the beginning of the 2030s below USD 120 billion and declining to USD 80 billion in 2050.
Annual clean energy investment has never exceeded USD 30 billion but must rise by a factor of five this decade to get on track for the SDS
Tapping into Southeast Asia’s potential for coal-to-natural gas switching can yield benefits for emissions, but its potential is not easy to realise Natural gas occupies a difficult space in Southeast Asia’s energy transition. It results in lower CO2 emissions and air pollutants than coal or oil, meaning it can avoid emissions and improve air quality when substituting for these fuels. But the emissions reductions from fuel switching in the region have been modest, and can be easily reversed. Substituting gas for coal and oil avoided around 20 Mt CO2 emissions in 2010 compared to 2000, yet switching from natural gas back to coal between 2010 and 2020 meant that emissions were nearly 40 Mt CO2 higher in 2020 than in 2010. Most of the increase in natural gas consumption since 2010 stems from increases in energy service demand from economic and population growth, rather than from fuel switching. Overall, natural gas has been responsible for 16% of the total growth in energy-related CO2 emissions in Southeast Asia since 2010, and has met 20% of total energy demand growth.
Executive summary The electrification of road transport is a major driver of decarbonisation in the IEA’s Net Zero Emissions by 2050 Scenario, and providing charging solutions will be crucial for supporting this transition. The power sector plays a key role in ensuring a secure supply of electricity for electric vehicle (EV) charging, and in taking advantage of EV flexibility through seamless integration with the power system. This manual is intended to support policy makers in assessing and mitigating the impacts of electric mobility on the power sector and designing strategies to leverage the flexibility of EVs. It provides key recommendations in four main areas: the readiness of institutions, impact assessment of EV charging, design of operational measures to integrate EVs as an energy resource, and power system planning.
Assess the power system impacts Electric vehicles (EVs) interact with the power system whenever they are connected to a charging point. Like many other electrical loads, EV charging can cause operational challenges and require upgrades based on the power drawn from the system and the specific location from which the power is drawn. The impacts can be classified as those affecting the capacity limits of the different components of the network, those that affect the power quality for the end users and those that affect the larger power system.
Deploy measures for grid integration Grid integration is the process of adapting power system operations to accommodate the entry of new energy technologies in a cost-effective manner. For distributed energy resources such as EVs, the following characteristics help distribution companies determine the extent to which the resource could affect or fully participate in the system.
Visibility: location information of the connected resource. For EV charging, this could entail information on the charging status of electric vehicle supply equipment (EVSE) and load profiles.
Control: the ability to influence the operation of the connected resource. For EV charging, this could include the ability to send signals to start and stop charging or to modulate the power of a connected EV.
Guidance: the ability of the network operator to provide locational guidance on where the connection should preferably take place, taking into account the minimisation of upgrade costs or the improvement of system performance.
EV hosting capacity map of New Jersey, United States
Varying local connection fees based on the available grid capacity can also serve as a locational signal. By passing a portion of the costs on to the CPO, they can then make a feasibility assessment of the charging station plans given possible higher charging rates. Making the connection fees more reflective of the needs of the grid can help avoid crowding in congested locations.
Vehicle-grid integration ecosystem and communication protocols
It is important to have a common communication protocol between the EVSE and the power system that is facilitated by managed charging actors. Currently, efforts are being made towards the global harmonisation of communication protocols, including those between EVs and EVSE, to aid in interoperability when crossing international borders. Standardised communication protocols bring about systemwide benefits but can also carry risks. Using insecure protocols that lack authentication and encryption can create entry points for cyberattacks. While it is not in the scope of this manual, policy makers should conduct a cybersecurity assessment and plan for mitigation measures for charging operations.
EV charging has strong potential synergies with renewables At the bulk energy level, load shifting of EV charging to more favourable times of the day can increase consumption and reduce the curtailment of transmission-connected renewables, leading to a better business case. In Korea, for example, flexible EV charging of 30% of the expected EV fleet in 2035 could reduce operating costs by USD 21/MWh and peak costs by USD 18/MWh, corresponding to 21% and 30% of the costs, respectively. It could also lead to a 63% emissions reduction compared to a full internal combustion engine fleet. Matching the EV load to the availability of renewables could also provide a better business case for renewable energy developers by reducing curtailment.
There are also potential synergies at the distribution level. Currently, areas with significant penetration of rooftop solar PV can experience problems with high local voltage (overvoltage) due to the injected energy not being matched with consumption. These conditions often arise during sunny weekends when consumption is low and PV generation is high. On the other hand, simultaneous EV charging in the evening when consumption is high can cause the opposite effect of low voltage levels (undervoltage). Co-ordinating the operation of EV charging and solar PV could increase the mutual hosting capacity within a distribution grid by keeping delivery within the contractual voltage limits. For example, a modelling study in Sweden shows that the distribution grid could host a higher penetration 12 of EVs and distributed PVs when co-ordinated with a management system compared to when they are uncoordinated.
Framework for grid integration of electric vehicles
Conduct proactive grid planning The typical process where grid operators respond to connection requests, in this case from EVSEs, can delay the rapid uptake of EVs. In some cases, connection requests can take from 6 months to over a year. Policy makers can streamline the interconnection process to help accelerate this process. As the number of EVs increases, the grid will eventually need to be reinforced and expanded. Reinforcing the grid to accommodate new load can take years for permitting and construction and can thereby slow down the electrification process. Additional new charging points can utilise the existing network. In many cases, however, fast-charging stations may require a new grid connection and grid reinforcement where the existing network capacity is constrained. The connection process from request to construction approval can be a lengthy procedure. Hence, proactively planning the grid can help anticipate the connection requests.
Coal markets have been shaken severely in 2022, with traditional trade flows disrupted, prices soaring and demand set to grow by 1.2%, reaching an all-time high and surpassing 8 billion tonnes for the first time. In last year’s annual market report, Coal 2021, we said that global coal demand might well reach a new peak in 2022 or 2023 before plateauing thereafter. Despite the global energy crisis, our overall outlook remains unchanged this year, as various factors are offsetting each other. Russia’s invasion of Ukraine has sharply altered the dynamics of coal trade, price levels, and supply and demand patterns in 2022. Fossil fuel prices have risen substantially in 2022, with natural gas showing the sharpest increase. This has prompted a wave of fuel switching away from gas, pushing up demand for more price-competitive options, including coal in some regions. Nonetheless, higher coal prices, strong deployment of renewables and energy efficiency, and weakening global economic growth are tempering the increase in overall coal demand this year. In China, which accounts for 53% of global coal consumption, prolonged and stringent Covid-19 lockdowns have weighed heavily on economic activity, undermining coal demand. At the same time, droughts and heat waves in China this summer accelerated coal burning to meet a surge in power demand for air conditioning.
Global coal demand breaches 8 billion tonnes threshold despite slow growth in 2022 Global coal consumption rebounded by a strong 6% to 7 929 million tonnes (Mt) in 2021, after a sharp decline the previous year due to the onset of the Covid-19 pandemic. A robust economic recovery, especially in countries that rely heavily on coal, such as the People’s Republic of China (hereafter “China”) and India, while higher natural gas prices prompted a wave of fuel switching to coal, with power generation up 8% to 5 344 Mt. Increased industrial activity boosted coal use for non-power applications by 2.2% to 2 585 Mt. China is by far the largest coal-consuming country, accounting for 53% of global demand. Overall, China’s coal consumption increased by 4.6% to 4 232 Mt in 2021, with the strongest growth in the first half of the year before slowing in the second half. Coal demand in India, the second-largest consumer, increased by an even sharper 14%, or 128 Mt, in 2021. Other countries reporting significant gains were the United States (+15%/+66 Mt), Germany (+19%/+26 Mt) and Poland (+12%/+13 Mt). Only a few countries recorded declines last year, with South Africa posting the largest fall at -5% (-9 Mt).
Global coal supply hits all-time high in 2022 but stalls by 2025 Despite deteriorating economic prospects, global coal supply is forecast to reach a new high in 2022 as demand for coal in power generation increases in response to tight gas markets and high prices. China and India continue to boost their coal production to overcome supply shortages, more than offsetting the decline in Russian production due to Western sanctions imposed in the aftermath of the country’s invasion of Ukraine. Global coal production is forecast to rise by 5.4% to 8 318 Mt in 2022, a new all-time-high and well above the record set in 2019. This follows an increase of 3.9% to 7 888 Mt in 2021 as economies recovered from the pandemic-induced demand drop in 2020. In absolute terms, 2021 growth was mainly driven by production increases of 153 Mt in China (4%) and 48 Mt in India (~6%). Steam coal and lignite accounted for 98% of the 295 Mt increase and around 86% of total production.
Global trade rebounded on strong demand in 2021, but will decline through 2025 International coal trade started slowly recovering from the economic fallout from Covid-19 in 2021, with volumes rising to 1 333 Mt for the year5 , accounting for ~17% of global coal demand. However, while the trade of thermal coal (which includes lignite and some anthracite) increased by 1.6%, metallurgical (met) coal trading volumes declined by 2.3%, reversing previous year’s developments. The great majority of coal traded in 2021 (93%) is seaborne. Traditionally, coal trade has been concentrated in the Pacific and Atlantic Basins, with South Africa and – to a lesser extent – Russia linking the two. However, international coal trade patterns shifted in recent years as Europe’s import demand declined and South African exports moved to the Pacific and the Indian Ocean. In 2021, however, surging natural gas prices reversed this development as coal import demand in Europe rose. Imports by Germany (38 Mt) surpassed Türkiye (36 Mt) again to make it the largest importer outside of Asia Pacific, which accounted for 79% of global coal imports.
Thermal coal trade declines but met coal trade increases through 2025
Thermal coal trade recovered in 2021 from a steep decline in 2020 After a Covid-19-induced decline, thermal coal trade rebounded to 1 025 Mt in 2021, led higher as the economic recovery gathered pace and by rising gas prices. Approximately 94% of the trade was seaborne. The share of the international coal trade in global coal demand decreased from about 16% to 15% as increasing imports were outpaced by growing demand, which was mainly met by higher domestic supply, particularly in China and India. The Asia Pacific is the most important thermal coal trading region: it was the origin of ~63% of all exports and the destination for about ~82% of all imports in 2021. Indonesian thermal coal exports accounted for ~42% of the global trade, raising its market share from ~40% in 2020. Australia ranked second, with a market share of ~19%, followed by Russia at 17%, South Africa at 6%, Colombia at 5% and the United States at 4%. China remained the world’s largest importer of thermal coal, increasing volumes by 16% to 284 Mt, followed by India and Japan. In 2021, India’s thermal coal imports contracted 10% to about 141 Mt. This was partly due to higher domestic production and buyers’ reluctance to pay higher prices, leading to severe coal shortages in the second half of 2021. Japan’s imports decreased to about 129 Mt. Thermal coal imports in Southeast Asia fell by 11 Mt to 126 Mt, mainly driven by a sharp decline in Viet Nam. Imports by the European Union rose strongly to 61 Mt (+25%) due to high gas prices.
Thermal coal imports are expected to contract through 2025 Imports of thermal coal are expected to expected to decrease slightly to 1 035 Mt in 2022. Thermal coal imports account for 77% of global coal imports and for 15% of overall thermal coal demand. The stagnation in 2022 is largely due to lower imports by China, which saw a significant ramp-up of domestic supply and a deceleration of demand growth. Strong increases in thermal coal imports from India and Europe offset the decrease. China’s thermal coal imports are forecast to decline by 44 Mt to 240 Mt in 2022. The country remains the world’s largest importer of thermal coal by far, but its share will edge lower from 28% to 23%. In February, imports tumbled to 9 Mt, the lowest level since November 2020, but recovered thereafter and reached previous year’s level in August. China significantly increased imports of Russian coal in the second half of the year as steep price discounts emerged following widespread Western bans and sanctions on the country’s energy supplies. In August, China imported 6.6 Mt of Russian coal, a sharp year-on-year increase of 2.2 Mt.
Growing met coal import demand met by Australia
International coal prices reach record highs – thermal coal even traded above coking coal After falling to 14-year lows in 2020, thermal coal prices rebounded strongly in 2021. Most international thermal price indices reached all-time highs in October, reflecting a supply-demand imbalance following the post-Covid-19 recovery, with coal and electricity shortages in China and India, to name the most relevant cases. Newcastle free on board (FOB) prices for high-grade thermal coal with a calorific value of 6,000 kcal/kg and the API2 prices (index for coal deliveries to Europe) reached an unprecedented USD 253/t and USD 254/t, respectively. Prices eased again by the end of the year as China’s efforts to increase production bore fruit, and coal inventories returned to normal. In January 2022, spot thermal coal prices were initially pushed up when the Indonesian government decided to suspend exports immediately in response to domestic supply shortages. At the end of January, Australian high-grade coal was trading at USD 261/t, which was a new record at the time, while prices in Europe (API2) traded lower at USD 206/t. Russia’s invasion of Ukraine triggered prices worldwide to skyrocket to another record high of USD 380/t in March 2022. European thermal coal prices caught up again with Australian prices. By contrast, South China’s import prices were less affected due to lower demand, enhanced domestic production and the opportunity to buy discounted Russian coal. With the end of the heating season in the Northern Hemisphere, global seaborne thermal coal prices softened briefly in April. In May, European and Australian prices picked up again. Australian high-grade thermal coal prices climbed straight to the next record high of about USD 425/t in May as flooding in the country hampered coal production and transportation while utilities in Europe and Northeast Asia sought to obtain supplies of non-Russian coal.
International thermal coal prices climb from record to record, while prices in China diverge
Coal supply costs increased in 2021 but prices rose more and profitability improved The supply costs for metallurgical coal are generally higher than those for thermal coal. This is because met coal is more often mined underground and, on average, comes from smaller coal mines than thermal coal. In addition, the preparation costs for met coal are higher than for thermal coal. In 2021, the cost of coking coal supply was relatively stable compared to 2020, but the amount of exported coking coal increased. In particular, Russia’s Elga low-cost coal mine, which ramped up exports in 2021, has placed itself at the beginning of the export supply curve for coking coal. As prices increased, so did the profitability of coking coal production. The average FOB price for Australian low-volatile met coal rose by 79% compared to the previous year.
Indicative hard coking coal FOB supply curve 2021 and average FOB marker prices
Record margins for coal producers
High prices hardly stimulate coal mining projects Two reasons could justify an uptick in coal investment. First, the unprecedented high prices prevailing since October 2021 have made thermal coal one of the best-performing commodities since then. Second, the energy crisis triggered by Russia’s invasion of Ukraine and its consequences, i.e. energy shortages, has renewed focus on energy security. Whereas the two above-mentioned factors undeniably impact market players’ moods, the analysis of the evolution of the individual projects and new ones does not show signs of significant acceleration in coal investment outside China and India.
Total coal consumption (Mt), 2020-2025
Acknowledgements, contributors and credits This publication has been prepared by the Gas, Coal and Power Markets Division (GCP) of the International Energy Agency (IEA). The analysis was led and co-ordinated by Carlos Fernández Alvarez, acting Head of GCP. Arne Lilienkamp, Jonas Zinke and Carlos Fernández Alvarez are the authors. Keisuke Sadamori, Director of the Energy Markets and Security (EMS) Directorate, provided expert guidance and advice. Other IEA colleagues provided important contributions, including Yasmina Abdelilah, Heymi Bahar, Louis Chambeau, Joel Couse, Laura Cozzi, Jean-Baptiste Dubreuil, Tim Gould, Astha Gupta, Tetsuro Hattori, Ciarán Healy, Martin Husek, YuJin Jeong, Javier Jorquera, Akos Losz, Gergely Molnár, Jinseok Rho and Hiroyasu Sakaguchi. Timely and comprehensive data from the Energy Data Centre were fundamental to the report. Laura Martínez and Nicola Dragui provided invaluable support during the process. Thanks go also to the IEA China desk, particularly Rebecca McKimm, Yang Zhiyu and Yang Biqing, for their research on China. The IEA Communication and Digital Office (CDO) provided production and launch support. Particular thanks go to Jad Mouawad, Head of CDO, and his team: Astrid Dummond, Jethro Mullen, Greg Viscusi, Isabelle Nonain-Semelin and Therese Walsh. Diane Munro edited the report.
Despite increasingly intense natural disasters and a high dependency on fossil fuels, Small Island Developing States (SIDS) have demonstrated strong leadership by setting ambitious climate targets and national energy policies in pursuit of Paris Agreement and Sustainable Development Goals. On-ground capacity building, project facilitation and access to international finance are critical to support SIDS in their energy transitions. Increasing the private sector’s participation as independent power producers and committing private capital towards renewable projects in SIDS was the focus of a week-long roundtable kicking off on Monday 28 August in Abu Dhabi, United Arab Emirates. The capacity building roundtable for islands in the Atlantic, Indian Ocean and South China Sea was organised by IRENA through its SIDS Lighthouses Initiative.
At the opening, IRENA’s Programme Officer for SIDS, Ms Arieta Gonelevu Rakai said: “The Agency through the Initiative has prioritised support for improving enabling frameworks for the increased deployment of renewables and the development of bankable renewable energy projects that will attract more private sector participation in SIDS.” The roundtable showcased the status of national energy policies, concrete lessons from project development including success stories and best practices on strengthening private sector engagement in Cabo Verde, Comoros, Maldives, Mauritius, Sao Tome and Principe, Singapore, and the Seychelles.
On the design of bankable power purchase agreements (PPA), Dr Laurent Sam from the Seychelles confirmed, “we are in the process of negotiating the first power purchase agreement with an independent power producer, so the training is timely and will help us revoke the barriers and simplify the process from tender to starting electricity production.” Mrs Nirkita Seeburn-Sobhun from Mauritius underlined the importance of investment. “We look forward to more knowledge sharing, best practices and lessons learned on the design of bankable PPAs and attracting private investment for renewable projects,” she added.
The roundtable builds on similar activities for the Pacific region and will also be replicated in the Caribbean region later this year. Each roundtable is being carefully planned by IRENA to improve and enhance the capabilities of power utilities and regulators, and to help SIDS design and negotiate bankable contracts. The Asian Infrastructure Investment Bank (AIIB) also provided an overview of their focus on green infrastructure investment and mobilising private capital in the energy, transport, water, urban and digital infrastructure sectors. Overall, the AIIB aims to disburse climate financing addressing mitigation, adaptation and resilience issues. IRENA gave insights on the support available through the SIDS Lighthouses Initiative, including energy access, geothermal development, grid assessment, project facilitation support and resource assessment.
El proyecto, integrado por 13 de empresas de ocho países diferentes, testará en el Mar Mediterráneo un innovador sistema flotante optimizado para aguas profundas que pretende hacer más competitiva a esta tecnología.
La iniciativa está respaldada por la Unión Europea a través del programa de financiación a la innovación Horizon Europe y tendrá una duración de cinco años.
Naturgy participa en un consorcio internacional para impulsar el desarrollo industrial y competitivo de la energía eólica marina en Europa. El denominado proyecto NextFloat implantará y testará un innovador sistema eólico flotante de 6 MW de potencia en el Mar Mediterráneo, frente a las costas de Francia, con el objetivo de probar su escalabilidad y futuro desarrollo comercial.
El proyecto ha sido respaldado por la Unión Europa y será financiado por el programa Horizon Europe, que impulsa distintos proyectos de innovación tecnológica en la región. Su duración será de cinco años.
El prototipo desarrollado por la startup catalana X1 Wind utiliza una tecnología disruptiva que pretende hacer más ligera la plataforma flotante sobre la que se asienta el aerogenerador, sustituyendo la tradicional torre por una estructura compacta en forma de trípode, lo que permite un menor uso de acero. Incluye además un sistema patentado, PivotBuoy, que permitirá a la plataforma orientarse pasivamente al viento, maximizando así su rendimiento energético y minimizando el impacto sobre el fondo marino gracias a su sistema de amarre denominado TLP.
El sistema será testado bajo condiciones reales durante tres años para su posterior localización en un futuro parque precomercial con turbinas de 15 MW.
El consorcio está formado por un conjunto de 13 empresas de ocho países diferentes entre las que se encuentran Technip Energies como coordinador del proyecto, X1 Wind, Naturgy, 2B Energy, Hellenic Cables, Technical University of Denmark, Hydro, Ecole Centrale de Nantes, Schwartz Hautmont, Ocas, Tersan Shipyard, Ocean Ecostructures y Cybernetix.
“Una transformación tan profunda como la que afrontamos en el sector energético obliga a que la innovación sea colaborativa y abierta, donde seamos capaces de generar simbiosis entre las grandes corporaciones como Naturgy y las startups, scale-ups, centros de investigación o universidades. El proyecto NextFloat, que engloba a todos estos agentes, nos permitirá aprender de los retos y desafíos a los que haremos frente, establecer nuevas alianzas dentro de la cadena de valor y adquirir know-how de cara al futuro despliegue de parques eólicos marinos en Europa”, explica Jesús Chapado, director de Innovación en Naturgy.
La integración de Naturgy en el consorcio NextFloat avanzará de forma paralela al desarrollo de otros proyectos de eólica marina en los que trabaja la compañía. En este sentido, el grupo mantiene un acuerdo con Equinor para impulsar distintos proyectos y extraer todo el potencial que tiene esta tecnología en aguas españolas. Ambas compañías ya trabajan conjuntamente en el proyecto Floating Offshore Wind Canarias (FOWCA), con el que quieren optar a la instalación de más de 200 MW de eólica marina flotante en el espacio marítimo del este de Gran Canaria.
Apuesta firma por las renovables Naturgy mantiene una apuesta muy importante por el desarrollo de las energías renovables y tiene previsto alcanzar los 14 GW de potencia instalada en 2025. La compañía tiene previsto invertir 14.000 millones de euros durante la vigencia del Plan Estratégico 2021-2025, de los que aproximadamente dos tercios se dedicarán al impulso de la generación renovable, para pasar de los 5,4 GW operativos actuales a los más de 14 GW previstos para estar operativos en diciembre de 2025. Estas inversiones confirman el giro estratégico de la compañía hacia un mix energético más sostenible y su compromiso con la transición energética. Todo ello, sin abandonar los objetivos fundamentales de creación de valor y crecimiento para cada uno de los negocios.
En el distrito holandés de Eemshaven, tres aerogeneradores funcionan ahora en un dique marino. Métodos de instalación innovadores: grúa trepadora y paneles CSM. El parque eólico Oostpolderdijk destaca nuevas opciones para utilizar diques.
Por primera vez, las turbinas eólicas ahora funcionan en un dique marino. En Eemshaven, dentro de la provincia holandesa de Groningen, RWE ha erigido tres plantas de energía eólica con una capacidad instalada de 7,5 megavatios, que entraron en pleno funcionamiento en septiembre de 2022. Para instalar de manera segura los componentes individuales en esta ubicación particular, con espacio limitado a su alrededor. , RWE se basó en algunos métodos de instalación innovadores. Para la instalación de los componentes superiores de la turbina, por ejemplo, se utilizó una grúa trepadora especial, que subió insertando segmentos individuales a medida que avanzaba la construcción. Además, las turbinas se instalaron en los llamados paneles CSM (Cutter Soil Mixing). En este proceso, el suelo existente se fortalece mezclándolo con hormigón y se cubre con una capa de arena sobre la que luego se construyen los cimientos. De esta forma, los aerogeneradores no están directamente conectados al subsuelo y pueden moverse con seguridad con él si el dique se asienta.
Katja Wünschel, CEO Onshore Wind and Solar Europe & Australia en RWE Renewables: Esta primicia mundial y todos los desafíos de instalación están dando sus frutos. Las condiciones de viento en este lugar expuesto son excelentes. Las tres turbinas generarán suficiente energía verde para abastecer hasta 7000 hogares holandeses al año. Y hemos obtenido información valiosa al completar este proyecto, lo que nos permitirá erigir parques eólicos en diques en otros lugares también. Mi agradecimiento particular va para la Junta de Agua de Noorderzijlvest y las autoridades de consentimiento involucradas por sus muchos años de cooperación constructiva”.
En los últimos años, RWE y el propietario del dique, la Junta de Aguas de Noorderzijlvest, analizaron meticulosamente el proceso de instalación, con miras a la seguridad del dique y los posibles impactos ambientales del proyecto, e incorporaron esto en un diseño técnicamente complejo. El aspecto más importante del proceso de desarrollo del proyecto fue la protección del dique para garantizar que su función de prevención de inundaciones no se viera afectada de ninguna manera.
The 2020 collapse in coal demand turned out to be smaller than anticipated Even before the pandemic, coal faced a difficult outlook for 2020. Demand was being squeezed by a mild winter in the Northern Hemisphere, low natural gas prices and strong renewables growth. When electricity demand and natural gas prices plummeted as the Covid-19 crisis escalated, coal-fired power generation bore the brunt of the impacts. Reduced industrial activity also hit coal demand, although in a more limited way. In the early months of the crisis, a double-digit annual decline in global coal demand looked plausible. But economic recovery in China came sooner and stronger than initially expected, with year-on-year growth resuming as early as in April. With economic recovery following elsewhere and a cold snap in December in Northeast Asia, global coal demand fell by 4.4% in 2020 – the largest decline in many decades but less than initially expected. The regional disparities were large. Coal demand grew by 1% in China in 2020 but dropped by nearly 20% in the United States and the European Union – and by 8% in India and South Africa.
We forecast that US coal production will continue to expand in 2022 before resuming its declining trajectory, which will lead to 484 Mt of output in 2024. The return to last decade’s production downturn reflects the anticipated drop in North American and European coal demand.
Furthermore, at the behest of the Czech Republic, in September 2021 the European Court of Justice ruled that operation of the Turow opencast lignite mine near the Czech border must cease because it endangers water supplies. Poland has rejected closure of the opencast mine on grounds of energy supply security, and bilateral negotiations are currently under way between the two countries. Through 2024, these decisions will have only a limited impact on Poland’s coal production, which is expected to decrease by 8 Mt to 99 Mt.
South Africa accounted for around 94% of Africa’s coal production in 2020, amounting to 247 Mt, down 4.4% from 2019. In 2021, its output is expected to decrease slightly to 244 Mt. Logistical problems, including civil unrest, train derailments and ongoing maintenance work on the export line to Richards Bay reduced coal exports, and domestic demand recovered only partially. Through 2024, South African coal production is expected to remain stable at the 2021 level, as a recovery to 2019 output is being prevented by the withdrawal of major mining companies such as Anglo American, as well as by cuts to planned domestic coal-fired power capacity. The only major new mine likely to become operational by 2024 is Seriti’s New Largo mine, for which construction began in 2020. Mozambique, Africa’s second-largest coal producer, had total production of 7 Mt in 2020, down from 11 Mt in 2019. The country was hit hard by the Covid-19 pandemic in 2020 and 2021, but coal production is expected to remain stable. Coal India conducts coal exploration in the country, and Ncondezi Energy has announced a 300-MW coal mine/power plant project, but no investment decisions have yet been made. Also, with Vale preparing to discontinue coal exploitation in Mozambique this year, future coal production in the country will depend on the operation’s new ownership. We expect coal production to increase, as current production capacity is not being fully utilised, with output in 2024 amounting to ~11 Mt.
For the next three years to 2024, we foresee global coal trade stability, with thermal coal volumes declining 1.9% per year and met coal increasing 2.8% annually. Thermal coal trade will be altered as China and India – the world’s two largest importers – raise domestic production to reduce import reliance, and as the European Union, Japan and Korea reduce their coal-fired power generation. Conversely, we expect higher volumes of met coal to be traded because China and India – the countries with the highest consumption – cannot raise their domestic production substantially, and because met coal demand for steel production remains high globally.
In 2020, 978 Mt of thermal coal were traded internationally – a 124-Mt drop from 2019 due to declining demand during the global pandemic. Approximately 916 Mt (94%) of this trade was seaborne. The share of internationally traded thermal coal in global coal consumption fell slightly to 15% in 2020. Annual data on thermal coal imports and exports are different, partly due to China’s trade practices and import quotas. Because of China’s quotas, ships that left ports at the end of 2019 were not discharged and registered as imports in China until January 2020. Therefore, higher values for imports than exports were recorded for 2020. Most seaborne thermal coal trade occurs in the Asia Pacific region, where the largest importers and exporters are both concentrated. Indonesia provided 41% of globally traded thermal coal in 2020, and Australia ranked second with 20%, increasing its market share from 19% in 2019. Other important exporters are Russia (18%), South Africa (8%), Colombia (5%) and the United States (2.5%).
Although the met coal market has only one-third the volume of the thermal coal market, international trade is more important for met coal. In 2020, about 318 Mt or 29% of total met coal consumed was imported, of which 286 Mt (88%) was acquired through seaborne trade. Met coal trade declined 33 Mt or 9% from 2019 to 2020. The market for met coal is highly concentrated on the export side, with Australia being the dominant global supplier (54% share in 2020). Other countries with significant market shares are the United States (12%), Canada (9%), Russia (12%) and Mongolia (7%). Asia Pacific countries accounted for 74% of all met coal imports in 2020, with China leading the way at 24%, although China’s imports were 8 Mt (-10%) lower than in 2019 because its domestic production had increased. Japan’s imports also decreased (‑ 9%) as its steel industry suffered significant production cuts due to the economic slowdown during the pandemic, as well as structural changes.
In 2020, global met coal consumption declined 3% to 1 100 Mt as steel production (outside of China) decreased, mainly due to pandemic-related effects. China is by far the world’s largest met coal consumer, accounting for 68% of the global total in 2020. Other significant met coal consumers were Russia (6%), the European Union (5%) and India (5%). In contrast with most other countries, met coal consumption in China increased slightly in 2020 (+0.7%/+5 Mt). The largest decline was in India (-22%/-16 Mt). We expect a slight increase of 0.5% in 2021, raising consumption to 1 106 Mt. As steel production recovers, met coal use increases in all major steel-producing regions, i.e. India (+17%/+9 Mt), the European Union (+9%/+5 Mt), Russia (+2.4%/+2 Mt) and Japan (+10%/+4 Mt). While consumption in China remained high in the first half of 2021, steel production fell in the second half of the year, directly affecting met coal demand and leading us to expect a decline in consumption (-3.9%). Despite the overall recovery in steel production, global met coal use remains below the 2019 level.
Nevertheless, as met coal remains a central element in steel production, consumption is forecast to increase to 2024, rising at an annual average of 1.7% to 1 164 Mt. Output of electric arc furnaces will depend on scrap availability, but our forecast assumes only a small increase in the EAF/BOF production ratio through 2024, based on historical trends. Alternative manufacturing processes such as hydrogen direct reduction will be marginal by 2024. While consumption in China flattens, growth in India (+14 Mt) and other developing economies continues as new blast furnaces are constructed to meet rising steel demand.
Indonesia is an extraordinary development success story When Indonesia declared independence in 1945, its GDP per capita was more than ten‐times lower than today. Since then, its economic development has been an extraordinary success story. From 1968 to today, Indonesia has been the fourth‐fastest growing large economy in the world, joining Korea, Singapore and China in sustaining very rapid growth over half a century. The share of the population below the national poverty line has fallen from 60% in 1970 to less than 10% today. Today, Indonesia is the world’s fourth‐most populous country, seventh‐largest economy, twelfth‐largest energy consumer, and the largest coal exporter.
Economic and social context Indonesia’s economy sustained a very severe hit during the Asian financial crisisin 1997, with GDP falling nearly 15% from its peak in 1997 and only regaining that level six years later. Recovering from the financial crisis, Indonesia’s GDP increased 4.9% per year from 2000 to 2021, although it experienced a 2.1% decline in 2020 owing to the Covid‐19 pandemic. In 2021, GDP expanded by 3.7%, lower than the historical average, as uncertainty around the pandemic lingered and the country experienced continued public health‐related restrictions. Nonetheless, in 2021 GDP recovered to above the pre‐pandemic level. GDP per capita was around USD 13 000 (PPP) (equivalent to about Indonesian Rupiah [IDR] 62 million per capita in 2021 at current prices). This puts GDP per capita in Indonesia at 70% of the global level and 55% of the G20 level (Figure 1.1). Indonesia is classified in the World Bank income classification as a lower middle‐income country, alongside economies such as Egypt and Tunisia. Despite its strong historical economic advances, Indonesia still requires strong economic growth to deliver high standards of welfare to its citizens.
Growing economic activity is the key driver of Indonesia’s increasing CO2 emissions (Figure 1.11). As the country’s population increased over the last two decades, welfare and consumption grew and economic output boomed. Population growth alone is responsible for about one‐fifth of the increase in emissions. But the primary driver of the substantial rise in CO2 emissions was the growth of GDP per capita, which accounted for more than half the increase in emissions. The increase in the carbon intensity of energy supply was responsible for about a quarter of the growth in emissions. However, the energy intensity of Indonesia’s GDP improved which helped to avoid a much bigger increase in emissions. Absent improved energy intensity, CO2 emissions would have almost quadrupled instead of the doubling that took place in the 2000‐21 period.
Natural gas Natural gas‐fired power plants provide another dispatchable source of electricity in Indonesia, albeit significantly smaller than coal. Through to 2060, natural gas use in power generation transitions from unabated to a lower emissions technology profile, both through the inclusion of CCUS and by co‐firing with hydrogen. The changing availability of domestically produced natural gas limits its role in terms of generation. Overall, the share of unabated natural gas in total generation falls by a few percentage points between 2021 and 2030 before decreasing to lessthan 1% in 2060 in the APS (Figure 3.4). Gas‐fired power plants also play an important role to support electricity security, providing flexibility and contributing to the reliability of the system.
In the megacity of Jakarta, motorbikes are by far the most common mode of transport for commuting, accounting for 64% of daily trips (Figure 3.20) (Sofiyandi and Siregar, 2020). More than two‐thirds of daily commutes are for distances of less than 30 km and 22% are under 10 km (BPS, 2015). The prevalence of motorbikes and relatively short daily travel distances offer an attractive opportunity for Indonesia’s largest city to shift to electromobility. The average home‐to‐work commuting distance of under 20 km can be easily served with battery‐ powered two/three‐wheelers available in markets today (Sofiyandi and Siregar, 2020). Electrifying Jakarta’s motorbike fleet could be achieved at limited additional cost and would benefit residents with improved air quality. Electric motorbikes are much more energy efficient than those that burn gasoline and so would help to reduce CO2 emissions in the near term even with Indonesia’s coal‐intensive electricity system. Maximising the mitigation benefits of electromobility requires decarbonising electricity generation.
Most Indonesians live in areas in which average daily temperatures exceed 25 °C. Even when and where temperatures are lower, high humidity levels increase perceived temperatures. Space cooling needsin Indonesia are among the highest in the world, with an average of over 1 500 cooling degree days per year. Comfort provided by air conditioners is available to only a fraction of the population today, with one‐in‐ten households having an air conditioner. Fans are much more common at an average of 1.5 units per household. With increasing income, purchasing an air conditioner is high on the list of priorities for many households and businesses. In the APS, air conditioner ownership increases to an average of 0.4 units per household in 2030 and almost 2 units per household in 2060, at which time there are 210 million additional air conditioners in Indonesia compared to today (Figure 3.28), with around 550 million units sold between today and 2060 as units are replaced.
In addition, it is both necessary and cost effective to develop the inter‐regional electricity system to allow the transfer of low emissions electricity from outside Java to load centres on the island. By 2050, transfer capacities of around 25 GW are required between Sumatra and Java, while around 17 GW are built between Kalimantan and Java, and around 16 GW between Java and Nusa Tenggara (Figure 5.20). These interconnections assist with balancing variable renewables, as well as with the transfer of bulk electricity between sources of low emissions supply and demand centres. They can build upon the very significant progress that has been made on the costs and performance of high‐voltage direct current (HVDC) transmission projects.
In parallel, public finance, including from DFIs, will be important to improve the financial and operational performance of state‐owned enterprises, PLN in particular. PLN is the main investor in the electricity sector in Indonesia and is the main counterparty to independent power producers (IPPs) in generation. However, PLN’s existing take‐or‐pay contracts (mainly with IPPs operating coal‐fired electricity generators) and a lack of cost‐reflective tariffs has been putting pressure on its balance sheet and government finances. Frozen tariffs since 2018, and a combination of government discounts introduced during the pandemic, lower electricity demand and reduced payment capability of consumers has added stress. DFI support in these areas – alongside necessary policy and regulatory changes – is essential to facilitate the phase‐out of coal.
Introduction Unprecedented events – the global coronavirus pandemic (Covid-19), the climate emergency and the turbulence in global energy markets, resulting from the Russian Federation’s (hereafter, “Russia”) invasion of Ukraine – have shocked the world in 2022. Unprecedented challenges, stemming from the triple global crisis require extraordinary actions to foster solidarity and fight the first and largest global energy crisis. In 2022, the G20’s lead on energy security and solidarity is more important than ever. Even before these events, the G20 has discussed and tackled a variety of related issues, proposing solutions and calls for action. In 2021 energy ministers at the G20 Ministerial in Naples, Italy, agreed on the G20 Naples Principles, which give guidance on collaboration towards maintaining and improving energy security during energy transitions. The objective of this report is to update and deepen the analysis, based on the G20 Naples Principles and with a specific focus on ways of maintaining and improving energy security during the current global energy crisis. It provides a series of recommendations to allow G20 countries to achieve secure clean energy transitions through important near-term actions which are aligned with long-term goals.
In the short term, there is a need to maintain energy security and rebalance supply and demand of energy by reducing demand and increasing supply, maximising the existing infrastructure, while radically reducing emissions of oil, gas and coal. This will help decrease pressure on global energy markets and prices. In March and April 2022, IEA member countries agreed to take collective action to release oil from their strategic reserves; the largest collective actions in the history of the IEA. IEA members underscored their strong and unified commitment to stabilising global energy markets, which was welcome by many G20 members. As these collective actions show, international collaboration and concrete actions are critical in ensuring the stable supply of energy, notably for developing economies. As underlined by the IEA report, Net Zero by 2050: A Roadmap for the Global Energy Sector, energy security becomes even more important on the way to net zero. Governments and industry must boost preparedness and resilience in the face of new and more frequent threats beyond traditional energy infrastructure disruption, such as cyberattacks and extreme weather events, particularly with regard to electricity infrastructure. The establishment of reliable and cost-effective supply chains for clean hydrogen and ensuring the adquacy of the global supply of critical minerals to meet the demand from ramping up clean energy technologies is part and parcel of achieving secure clean energy transitions.
Growing electricity demand and electrification Electricity plays a growing role in all economies and its share of total energy demand is expected to grow universally under the impetus of improving living standards and electrification of end uses. The need to expand access to affordable and clean energy to all citizens, in line with the United Nations’ Sustainable Development Goal 7 (SDG7), continues to be a critical driver of electricity demand growth. As household incomes increase, more appliances are connected and electricity demand rises. While emerging economies are on track to achieve universal access by 2030, developing economies in sub-Saharan Africa and developing Asia are at risk of not meeting the target (figure below).
Preparedness and response to global energy crises Traditional energy security risks related to oil and gas supply have been back in the spotlight due to rapid economic recovery after the Covid-19 pandemic and Russia’s invasion of Ukraine. While energy transitions raise new challenges to energy security, traditional supply security risks linked to fossil fuel use, notably oil and gas, continue to play an important role in ensuring sufficient energy supply. It should be noted that demand for oil and gas is recovering robustly and this trend is expected to continue, even during clean energy transitions, far above the path required to achieve net zero. But energy security is evolving, and the extent and type of risks to energy supplies are broadening, requiring countries to anticipate and manage both existing and newly emerging energy security challenges. Accelerated transitions are likely to amplify both old and new security factors, requiring the bolstering of resilience and emergency response capacities to ensure the uninterrupted flow of affordable energy.
Oil and gas remain significant during energy transitions Oil and gas consumption will remain important during the transition. Even under the IEA Net Zero Scenario, the dependency of developing Asia on oil and gas imports remains high, notably on OPEC+ supplies.
Price may also heavily influence the uptake of critical minerals. The price of many minerals and metals that are essential for clean energy technologies have recently soared due to a combination of rising demand, disrupted supply chains and concerns around tightening supply. The prices of lithium and cobalt more than doubled in 2021, and those for copper, nickel and aluminium all rose by around 25% to 40%. The price trends have continued into 2022. The price of lithium has increased by an astonishing two and a half times since the start of the year. The price of nickel and aluminium – for which Russia is a key supplier – has also kept rising, driven in part by Russia’s invasion of Ukraine. For most minerals and metals that are vital to the clean energy transition, the price increases since 2021 exceed by a wide margin the largest annual increases seen in the 2010s. While innovation and economies of scale rapidly reduced the cost of key clean energy technologies such as solar PV and batteries, surging raw material prices could now reverse these gains, with a major impact on the financing needs for clean energy transitions around the world. Raw materials now account for a significant and growing share of the total cost of clean energy technologies.
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