This is an extract from a recent report “World Energy Outlook 2024” by IEA. In this extract, we specifically focus on the European Union (EU) and Eurasia.

The European Union (EU) is home to 6% of the world population and accounts for approximately 10% of global energy demand. It continues to be a clean energy leader, with energy-related CO2 emissions in 2023 declining more steeply than in 2022, driven by increased electricity production from renewables, a recovery in hydro and nuclear power, reduced emissions in industry, plus a mild winter. Many aspects of the EU Fit for 55 package, which is the implementation framework for the European Union Green Deal, are moving forwards: recent developments include revision of the EU Emissions Trading System and CO2 emissions standards for heavy-duty vehicles. In the STEPS, oil demand in the European Union is set to drop by 15% from today’s levels by 2030, natural gas demand by around 10% and coal demand by nearly half. CO2 emissions fall by almost 50% from their 1990 level. The share of electric cars in new registrations expands from just under 25% today to 100% by 2035, and the share of renewables in electricity generation rises from 45% today to around 80%. The outlook for heat pump sales is generally positive, although a slowdown in sales in 2023 looks to have continued into 2024: the growing role of heat pumps in meeting energy demand in buildings contributes to a reduction of nearly 5 billion cubic metres (bcm) in gas use in 2030 compared with today. Policy developments in France, Sweden, Poland and Belgium are reinforcing the role of nuclear power in the European Union. In the APS, faster progress is made, including on ambitious components of the Fit for 55 such as retrofit targets for buildings. The result is to reduce fossil fuel demand by 20% in 2030 compared to 2023, to reduce CO2 emissions by 55% relative to 1990 levels, and to meet the REPowerEU goal of eliminating dependence on natural gas from Russia before 2030.

The European Union aims to become a hub for clean energy manufacturing; the new Net Zero Industry Act sets a goal for EU manufacturing capacity to reach at least 40% of its annual clean energy deployment needs by 2030. The European Union was the world’s secondlargest installer of most clean technologies in 2023, second only to China. EU member states added almost 60 GW of solar PV capacity, with over 60% coming from rooftop installations, twice the level seen in 2021. Member states integrated over 15 GW of wind capacity, an increase of 40% compared to 2021. Expanding clean technology adoption in the European Union continues in each scenario, with installed capacity of wind and solar PV projected to more than double from the 2023 level in the STEPS by 2030. Annual electric car sales rise from around 2.5 million units today to over 7 million units in 2030 in the STEPS, accounting for nearly 20% of global EV sales. Announced battery manufacturing capacity is set to swell by four- to six-times by 2030 from current levels. Similarly, annual heat pump sales increase from 25 GW today to over 45 GW in 2030, driven by supportive regulations and financial incentives. 

European consumers were heavily exposed to price spikes during the global energy crisis, but there are signs that the outlook is improving. Electricity prices for households fell on average by over 10% year-over-year in 2023, and wholesale natural gas prices dropped nearly 70% from the extremely high levels seen in 2022, though they remain higher than in 2021. Tightness in natural gas markets should be eased by the new LNG export terminals that are due to come online from 2025, primarily in Qatar and the United States, adding over 250 bcm of capacity by 2030. Since Russia invaded Ukraine, efforts to diversify gas supply have cut the share of total EU energy imports from Russian pipeline gas from over 40% in 2021 to below 10% today. This is due in part to efforts to improve energy efficiency and boost renewables, but it also reflects a major switch away from Russian pipeline gas to LNG, which now accounts for more than 40% of European Union gas imports.

The drive to decarbonise power generation and the impacts of the energy crisis together have brought the cost structures of electricity systems in EUs member states under close scrutiny. Clean energy transitions depend heavily on electrification and expansion of renewables, both of which require significant changes in electricity systems. The diversity of electricity mixes and decarbonisation pathways chosen by the various member states adds to the challenges. Between 2019 and 2023, the average system cost per unit of generated electricity, including the development and maintenance of grids, reached USD 145/MWh in the European Union, which is 60% higher than in the United States, and around 10% higher than in other advanced economies. A key factor behind this difference is the cost of repaying past capital investment in the European Union, which is nearly double that of the United States, and accounted for a third of total system costs on average in the 2019-2023 period. These higher costs stem from the European Union’s early efforts to develop low-emissions electricity sources, and in particular from its work in pioneering the large-scale deployment of wind and solar PV in the 2010s at a time when they were nascent technologies and relatively expensive compared to today. 

Also contributing to high electricity costs in many EU member states is the cost of fossil fuel used in electricity generation, including natural gas imports. This accounts for around a quarter of electricity costs across the European Union. While member states have significantly reduced their reliance on coal for electricity generation in recent years, and more recently have significantly cut natural gas pipeline imports from Russia, the extent to which many of them depend on natural gas imports continues to drive up overall electricity costs. EU member states that rely less on natural gas for power generation, such as Denmark, France and Sweden, are less exposed to these high fuel costs. Clean energy transitions provide an opportunity for EU member states to reduce their average electricity system costs. Continuing the shift from coal- and gas-fired power plants to low-emissions electricity sources could reduce total EU electricity system costs by around 12% by 2035. Additional decarbonisation efforts in the APS and achievement of the REPowerEU objectives could reduce system costs a further five percentage points. Investment levels needed for renewable energy sources and grid development are large, but the cost per unit of electricity for the grid component is similar to that in other parts of the world, and investment in renewables is necessary to reduce future electricity costs and GHG emissions. The accelerated transition seen in the APS leads to a more rapid fall in electricity costs.

Average electricity system costs are not the same as end-user electricity prices, and one of the challenges of energy transitions is ensuring that reductions in electricity system costs are reflected in consumer tariffs. Reforms in electricity market design and use of instruments such as long-term contracts, including contracts for difference or power purchase agreements, can help align electricity prices with system costs. The expansion of renewables, the growth of nuclear capacity and the development of flexibility sources should all also weaken the link between the costs of natural gas-fired power generation and wholesale electricity market prices. Changes along these lines are likely to lower electricity prices and reduce exposure to fossil fuel price volatility while maintaining an efficient balance between supply and demand. The expansion of renewables will not do much to lower overall electricity costs if they cannot be successfully integrated into electricity systems. Grid congestion and redispatch costs, which hit EUR 4 billion in 2023, are expected to rise, underlining the crucial need to invest in grid infrastructure and to expand interconnections (ACER, 2024). The investment required is necessary to unlock the benefits of renewables and would be offset by the savings gained from reduced fossil fuel imports. Delays in investing in the necessary grid infrastructure and the provision of flexibility are all too likely to result in increased congestion and price cannibalisation from surplus generation that cannot be integrated. Over time, this could undermine producer revenues and overall security of supply. Further European Union electricity market integration would also help to foster integration of renewables, ensure reliable supply and mitigate price differences between bidding zones.

Eurasia

In Eurasia, which comprises the Caspian region and the Russian Federation in our modelling, GDP per capita rose over 3% in 2023 to reach a level 30% higher than the global average. Russia plays an outsized role in the energy architecture of the region, but the continuing war between Russia and Ukraine, following Russia’s full-scale invasion in 2022, is shifting priorities and creates huge uncertainty for projections of energy demand and supply. The loss of Europe as its key export market prompted Russia to reach out to its Central Asian neighbours to expand energy partnerships and reinvigorate long-standing plans to deliver natural gas to Kazakhstan, Uzbekistan and further afield, though there remains significant uncertainty around the pace and scale of these diversification efforts. The energy sector in Eurasia faces challenging conditions. Ageing building stock and industrial facilities, under-maintained pipelines that transport fuel over large distances, and a cold climate mean that the regional energy intensity of GDP is 70% higher than the global average. There are inefficiencies in energy supply, distribution and use. Fossil fuels are heavily subsidised in Eurasia, notably Russia, Kazakhstan, Uzbekistan, Turkmenistan and Azerbaijan. These subsidies total over 6% of the region’s annual GDP. Eurasia is both a major consumer and producer of fossil fuels. In 2023, fossil fuels constituted 90% of Eurasia’s energy demand, the second-highest regional average after the Middle East. The region is also a large net exporter of fossil fuels, selling around 200 bcm of natural gas in 2023, along with nearly 10 mb/d of oil and 175 Mtce of coal. Russia accounts for around 75% of the region’s oil and gas exports, although these have been significantly affected by sanctions imposed after its invasion of Ukraine: in 2023, Russia’s natural gas exports were at half their pre-war level of around 250 bcm. 

With current policy settings, the share of fossil fuels in the region’s energy mix is projected to remain high. By 2035, fossil fuels account for nearly 90% of the energy mix in the STEPS, staying broadly constant to 2050. Oil demand rises 8% by 2035 as a result of growth in the transport and industry sectors. Natural gas demand in the STEPS remains almost unchanged, with just a 2% increase by 2050. This small change comes mostly from the power sector, where gas demand grows by 7%. Almost half of the increase in electricity consumption in the STEPS to 2035 is met by fossil fuels. Renewable capacity nearly doubles between 2023 and 2050, which is the lowest regional rate of growth in the STEPS. Hydropower remains the dominant source of renewable electricity in 2050. Azerbaijan will host the 29th Conference of the Parties, the annual United Nations Framework Convention on Climate Change conference in 2024. It is a significant opportunity to strengthen the regional collaboration related to energy trade, clean energy investment, methane reduction efforts and energy efficiency commitments. All countries in the Caspian region are signatories to the Global Methane Pledge. Six-out-of-nine Eurasian countries have committed to the COP28 Global Renewables and Energy Efficiency pledge to triple renewables capacity and double the global annual rate of energy efficiency improvements by 2030. Kazakhstan, Georgia, Russia, Kyrgyzstan and Armenia also have longer term net zero emission targets.

If announced national energy and climate pledges are achieved in full and on time, as in the APS, this would move the region’s energy system onto a very different footing. In the APS the share of fossil fuels in the energy mix in Eurasia falls to 75% by 2050, driven by rapid deployment of renewables and nuclear capacity. Natural gas demand drops nearly 15% (85 bcm) by 2035, while a rise in the sales share of electric cars from 1% to 20% help to generate a 3% fall in oil demand by 2035. Coal undergoes the steepest decline in demand among fossil fuels: it falls about 30% by 2035. This drop in fossil fuel use is produced by a rapid rise in clean energy investment, which more than triples to 2035, resulting in a doubling of renewables capacity in the power sector over the same period. It also requires large-scale modernisation of the region’s electricity grids. These efforts bring about a peak in CO2 emissions in the APS by the mid-2020s, and emissions in the APS are 30% lower in 2050 than current levels, compared to 4% in the STEPS.

Turkmenistan, Azerbaijan, Kazakhstan and Uzbekistan face a common challenge as major gas producing countries in the Caspian region to maintain ageing gas infrastructure while meeting rising demand, which is often heavily subsidised. Upgrades to the gas infrastructure have a critical role to play in the broader modernisation of the region’s energy system, alongside the expansion of renewables, and as a way to unlock needed improvements in energy efficiency. Over 15% of the world’s natural gas is transported in pipelines that traverse Russia and the Caspian region. Much of this infrastructure was built during the Soviet era, and its condition has deteriorated in many cases due to a lack of investment. As a result, many Caspian countries suffer from power rationing, outages and even blackouts, as well as major fugitive methane emissions. Taking action to reduce methane emissions is highly cost effective. Around 10 Mt of methane in the Caspian region is estimated to be lost as fugitive emissions each year and an additional 2 Mt are flared. If instead this natural gas had been exported in 2023, it would have been worth up to USD 8 billion. Improving the efficiency of the ageing infrastructure could cost USD 500 000 to USD 3 million per kilometre depending on the location, while the annual investment cost of tackling methane emissions to 2030 is estimated at around USD 700 million. Without action to improve energy efficiency and upgrade infrastructure, some countries are likely to see increasing strains on their natural gas balance. Kazakhstan and Uzbekistan are already struggling to meet rising domestic natural gas demand, compelling them to reduce gas exports to China in 2023.

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