Overall, the report provides in total data for 243 plants in 24 countries.1 Figure ES.1 provides a synthesis of the different technologies analysed and the range of their LCOEs at plant-level at a real cost of capital cost and a corresponding discount rate of 7%. Given the increasing importance of system considerations for a comprehensive comparison of different technologies, the LCOE analysis is complemented by examples of the IEA''s value adjusted levelised costs of generating electricity (VALCOE) measure for selected regions and technologies.
Electricity from new nuclear power plants has lower expected costs in the 2020 edition thanin 2015. Again, regional differences are considerable. However, on average, overnight construction costs reflect cost reductions due to learning from first-of-a-kind (FOAK) projects in several OECD countries. LCOE values for nuclear power plants are provided for nth-of-a- kind (NOAK) plants to be completed by 2025 or thereafter.
Coal- and gas-fired units with carbon capture, utilisation and storage (CCUS), for which only the United States and Australia submitted data, are, at a carbon price of USD 30 per tonne of CO2, currently not competitive with unmitigated fossil fuel-plants, nuclear energy, and in most regions, variable renewable generation. CCUS-equipped plants would constitute a competitive complement to the power mix only at considerably higher carbon costs.
The LCOE calculations are based on a levelised average lifetime cost approach, using the discounted cash flow (DCF) method. Costs are calculated at the plant level (busbar), and therefore do not include transmission and distribution costs. The LCOE calculations also do not capture other systemic costs or externalities beyond plant-level CO2 emissions such as, for instance, methane leakage during the extraction and transport of natural gas. This report does however recognise, in particular in Chapter 4, the importance of the system effects of different technologies, most notably the costs induced into the system by the variability of wind and solar PV at higher penetration rates.
The aggregated data for the 24 countries that provided data for this report does not tell the whole story of levelised generation costs. Due to more or less favourable sites for renewable generation, varying fuel costs and technology maturity, costs for all technologies can vary significantly by country and region. In addition, the share of a technology in the total production of an electricity system makes a difference to its value, load factor and average costs.
Whereas renewables are very competitive in most countries participating in this report, the data provided for Projected Costs of Generating Electricity – 2020 Edition shows that they still have higher costs than fossil fuel- or nuclear-based generation in some countries (in this report: Japan, Korea and Russia). Also within countries, different locational conditions can lead to differences in generation costs at the subnational and local level. In Europe, both onshore and offshore wind as well as utility scale solar installations are competitive to gas and new nuclear energy.
In the United States, gas-fired power plants benefit from the expected low fuel prices in the region, although fuel price assumptions are, in general, uncertain. Nevertheless, in terms of the LCOE of the median plant, onshore wind and utility scale solar PV are, assuming emission costs of USD 30/tCO2, the least cost options. Natural gas CCGTs are followed by offshore wind, nuclear new build and, finally, coal.
In China and India, variable renewables are having the lowest expected levelised generation costs: utility scale solar PV and onshore wind are the least-cost options in both countries. Nuclear energy is also competitive, showing that both countries have promising options to transition out of their currently still highly carbon-intensive electricity generation.
In the default case with emission costs of USD 30/tCO2, equipping coal and gas plants with a CCUS is, due to the higher investment costs of CCUS equipment and the reduced thermal efficiency, more expensive than unmitigated fossil fuel-based electricity.
With higher emission costs however, the picture could change. For coal power plants, due to the fuel''s relatively high carbon content, CCUS units become competitive at around USD 50 to 60 per tCO2. For gas-fired CCGTs, only carbon prices above USD 100/tCO2 would make plants with CCUS competitive. At such high carbon prices, renewables, hydroelectricity or nuclear are likely to constitute the least-cost options to ensure low-carbon electricity.
Although the necessary carbon price levels required for triggering a cost advantage of CCUS plants exceed the majority of today''s prices, they are still relatively low compared to existing estimates of the social cost of carbon. Although the estimates carry great uncertainties, global social costs could exceed USD 100 per tCO2 (Nordhaus, 2017). Thus, if flexible low-carbon generation is needed, competitive alternatives are lacking and affordable fossil resources are available, CCUS may become an option. Depending on national circumstances, with sufficiently high carbon prices, CCUS could be a possible complement in certain low-carbon power mixes.
To enhance the comparability of costs between regions and markets, it was necessary to harmonise certain assumptions. Therefore, in the base cases of our analyses we assume an 85% capacity factor for nuclear, coal and CCGT plants as well as a 7% discount rate. Depending on the individual market, these parameters can differ significantly, based on the existing technology mix as well as the market environment.
With increasing shares of renewable generation for example, baseload plants may lose market share and have to content themselves with satisfying the residual demand. This is why this report includes also estimates for 50% load factors for dispatchable baseload technologies such as gas, coal and nuclear. In practice, load factors are country and system specific, but capacity factors of this magnitude are not uncommon, both in OECD and non-OECD countries.3 Depending on their position in the merit order, technologies will be affected differently. In the United States, with its low gas prices, for instance, coal units will typically be dispatched last, and will have lower capacity factors.
The results show that, due to their relatively low investment costs and in many regions moderate variable costs, gas-fired CCGTs are well suited for handling different generation levels. Nuclear units on the other hand, due to high investment costs, require high utilisation rates.
The more capital-intensive a technology, the more sensitive is its LCOE is to changes in the discount rate. Among baseload plants, this means that in particular the costs of nuclear new build depend on the discount rate. With a low discount rate of 3%, reflecting a stable market environment with high investment security, the LCOE of new nuclear plants is lower than for new coal and gas plant. With higher discount rates at 7% or 10%, which would reflect riskier economic environments, the costs of a newly built nuclear plant would exceed those of fossil fuel-based plants.
In order to complement the LCOE approach and enable a more system specific cost comparison, the IEA has developed a methodology to adjust the costs by a system value component known as the value adjusted LCOE (VALCOE). It modifies the LCOE of an individual technology in a particular electricity system according to its contribution to enabling all aspects of securely operating the system. Crucially, the calculated results reflect the value in existing, i.e. brownfield systems and their possible future development.
Assessing the system contribution of different generation technologies provides a more complete picture of their economic costs. However, in order to obtain a measure of their full costs to society, the impacts on human health (both through air pollution and through major accidents), the environment, employment, the availability of natural resources and the security of supply need to be included (see, for instance, NEA 2018).
Storage could complement variable renewable generation to improve the alignment of, for example, wind and solar PV generation with electricity demand. In future low-carbon systems, a mix of multiple flexibility options, for example storage, demand flexibility and flexible low-carbon output from, for instance, nuclear and hydro plants is likely to provide minimal cost solutions.
To better understand the future of storage, its role in energy systems is scrutinised repeatedly throughout the report. Expected cost data for 2025 form the basis for further analysis, followedby a thorough discussion about options for measuring the competitiveness of storage through enhancing the LCOE methodology to come up with a levelised cost of storage (see Chapter 8). One important insight is that storage refers to a continuum of technologies with different ratios of energy to capacity (E/P) as well as different costs, load factors and economic roles in the complex system interactions of modern electricity systems.
Five "boundary chapters", free-standing articles contributed by experts in the respective areas, complement the report - considering wider issues related to the costs of electricity generation and broadening the scope of the core analysis.
The 2020 edition of the Projected Costs of Generating Electricity series is the first to include data on the cost of storage based on the methodology of the levelised costs of storage (LCOS). Chapter 6, a contribution from researchers at the Department of Mechanical Engineering at KU Leuven, shows how to calculate the LCOS according to transparent and robust protocols – accounting for the differences between storage technologies.
Chapter 7 constitutes a synthesis of the state of knowledge about the impacts of carbon pricing in the electricity sector. The collaboration by researchers from the NEA and the Swedish Environmental Agency provides an overview of current carbon pricing initiatives and their impacts on the economy, carbon emissions, electricity prices and distribution. It analyses potential advantages of allocating carbon emission cost to taxpayers rather than to electricity consumers.
As identified in the 2019 IEA report Nuclear Power in a Clean Energy System and confirmed in this report, life extension of existing nuclear power plants can be a highly cost effective investment opportunity for low-carbon generation. Chapter 8, authored by the NEA, presents an up-to-date view of the potential role of nuclear energy in decarbonised electricity systems. Ithighlightsthe cost advantages of lifetime extensions (LTO), potentially significant cost reductions for new constructions after gaining experience with new designs and the potential of small modular reactors (SMRs).
To reduce energy-related emissions, it is not sufficient to decarbonise the electricity sector, but electricity also has to replace fossil fuels in other end-use sectors. Chapter 9 is a contribution by the French electricity TSO (transmission system operator) RTE on the transformation of the overall energy sector through electrification and sector coupling. It concentrates on the impacts of the increasing penetration of electric vehicles, industrial hydrogen use and energy efficiency measures in residential heating on electricity demand and supply in France and Europe until 2035 – stressing the increasing need for comprehensive system analyses.
Chapter 10, a contribution by the IEA, presents a detailed discussion of hydrogen as a potential key element in the transition towards a clean, secure and affordable future energy system, further strengthening the need to adopt a system perspective. Based on the 2019 IEA report The Future of Hydrogen: Seizing Today''sOpportunities, the chapter highlights the critical role of the power sectorin the realisation of the new emerging opportunity, but also potential barriers and necessary next steps. It concludes the five boundary chapters taking a broad, forward-looking approach to a changing energy world.
The report also considers for the first time in some depth the costs of the system effects of different generating options, most notably the variability of wind and solar PV. Such system analysis will become increasingly important as their penetration in the electricity systems of OECD and non-OECD countries increases. Logically, the costs of storage are also included for the first time. Lastly, this report provides a perspective on the coming electrification of sectors such as transport, hydrogen or heat production, which will integrate electricity generation with the wider economy in new and important ways. The chances are that these latter two aspects will play an even greater role in future editions of the Projected Costs of Generating Electricity.
Participating countries include five non-OECD countries: Brazil, the People''s Republic of China (hereafter China), India, Romania, the Russian Federation (hereafter Russia) and South Africa. Romania and Russia are, however, member countries of NEA. Brazil, China and India are association countries of the IEA and key partners of the NEA.
The influence of carbon costs on the LCOE of fossil-fuel based generation is analysed in Chapter 5. However, the report does not systematically compare all technology LCOEs for different carbon costs.
With very high shares of variable renewables, also for example wind and solar PV might have to be curtailed, depending on the available flexibility options. Their load factors would then be below their theoretical maximum that would increase the reported LCOE values.
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