Projected Costs of Generating Electricity 2020

Projected Costs of Generating Electricity – 2020 Edition is the ninth report in the series on the levelised costs of generating electricity (LCOE) produced jointly every five years by the International Energy (IEA) and the OECD Nuclear Energy Agency (NEA) under the oversight of the Expert Group on Electricity Generating Costs (EGC Expert Group). It presents the plant-level costs of generating electricity for both baseload electricity generated from fossil fuel and nuclear power stations, and a range of renewable generation – including variable sources such as wind and solar. For the first time, this edition also includes cost data on storage, fuel cells and the long-term operation (LTO) of nuclear power plants. It is a forward-looking study, based on the expected cost provided by participating countries of commissioning these plants in 2025, which assumes moderate carbon costs of USD 30 per tonne of CO₂.

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.

The key insight from this 2020 edition is that the levelised costs of electricity generation of low- carbon generation technologies are falling and are increasingly below the costs of conventional fossil fuel generation. Renewable energy costs have continued to decrease in recent years. With the assumed moderate emission costs of USD 30/tCO₂ their costs are now competitive, in LCOE terms, with dispatchable fossil fuel-based electricity generation in many countries.2 In particular, this report shows that onshore wind is expected to have, on average, the lowest levelised costs of electricity generation in 2025. Although costs vary strongly from country to country, this is true for a majority of countries (10 out of 14). Also solar PV, if deployed at large scales and under favourable climatic conditions, can be very cost competitive. Offshore wind is experiencing a major cost decrease compared to the previous edition. Whereas five years ago, the median LCOE still exceeded USD 150/MWh, it is now significantly below USD 100/MWh and therefore in a competitive range. Both hydro technologies analyses (run of river and reservoir) can provide competitive alternatives where suitable sites exist, but costs remain very site-specific. The result of IEA’s value adjusted LCOE (VALCOE) metric show however, that the system value of variable renewables such as wind and solar decreases as their share in the power supply increases.

Electricity from new nuclear power plants has lower expected costs in the 2020 edition than   in 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.

Nuclear thus remains the dispatchable low-carbon technology with the lowest expected costs in 2025. Only large hydro reservoirs can provide a similar contribution at comparable costs but remain highly dependent on the natural endowments of individual countries. Compared to fossil fuel-based generation, nuclear plants are expected to be more affordable than coal-fired plants. While gas-based combined-cycle gas turbines (CCGTs) are competitive in some regions, their LCOE very much depend on the prices for natural gas and carbon emissions in individual regions. Electricity produced from nuclear long-term operation (LTO) by lifetime extension is highly competitive and remains not only the least cost option for low-carbon generation - when compared to building new power plants - but for all power generation across the board.

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.

Beyond investments in new sites (greenfield projects), this report includes levelised cost estimates for the long-term operation of nuclear plants (LTO) – representing extensive refurbishments to enable a secure operation beyond the originally intended lifetime. The report shows that this brownfield investment, i.e. making use of the existing facilities and infrastructure, significantly reduces costs compared to building new greenfield plants. Even at lower utilisation rates, a potential scenario for nuclear units in systems with high shares of variable renewables, costs are below those of new investments in other low-carbon technologies. Other low-carbon technologies with long lifetimes, in particular hydroelectric plants, could be similarly attractive for such LTO investments but no cost data was submitted.

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.

A key determinant of competitiveness is the discount rate, which corresponds in the LCOE methodology to the cost of capital. In its central case, this report assumes a uniform discount rate of 7% for all technologies and countries. In practice, the discount rate reflects, among others, opportunity costs of investment as well as different kinds of risk and uncertainty, for example regarding political and regulatory developments, the market design, the system development and future investment and fuel costs. Furthermore, in the real world the question of who bears the risk is important: Government support, in the form of price guarantees for example, would shift the risk from the investor to the public. Long-term power purchasing agreements would allow sharing the risk between project developers and electricity buyers. Although the overall risk remains the same, the investment would thus become cheaper from an investor perspective. Such factors, which can be important at the level of an individual project, do not appear explicitly in the LCOE numbers provided in this report, which does not include considerations of contractual structure or market intervention.

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.

The LCOE is a well known and, thanks to its relative simplicity and transparency, well understood metric for comparing different generation technologies. The common assumptions made in this report – for example assuming identical capacity factors for gas, coal and nuclear plants across regions – ensures that cost differences can be clearly identified. However, this approach neglects the differences in individual systems and markets that considerably influence the competitive position of technologies. These system-specific characteristics interact with the technical and economic characteristics of different technologies, i.e. their variability, dispatchability, response time, cost structure and place in the merit order. This also includes the fact that not all units are dispatched to the same extent across technologies and markets, or that revenues in many markets are determined by fluctuating prices and not, as assumed in the LCOE analysis, by a stable price over a technology’s lifetime.

More importantly, the LCOE metric applies to the level of the individual plant and does not address the value that different generation technology options add to the electricity system at different levels of penetration. The electricity generation of variable renewables of a particular type is correlated and not reliably available at all times. The simultaneity of generation, which is not necessarily correlated with demand, reduces the value of generation. The lack of reliability requires either dispatchable back-up or, alternatively, flexibility options such as storage or demand response to ensure security of supply at all times. Additionally, potentially rapid changes in variable renewable generation need to be balanced. To understand this impact and to ensure that a given demand is satisfied with low-carbon electricity at least cost, electricity system-level analysis is required (see IEA, 2019 and NEA, 2019). Overall, this means that LCOE increasingly needs to be contextualised by other analyses in order to obtain a meaningful picture of the relative competitiveness of different electricity generating technologies.

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.

The results illustrate that a technology’s plant-level generating costs can vary significantly from its value to the system. The importance of taking this into account is especially striking when considering variable renewables: solar PV units show a high correlation in the output of individual plants resulting, in the analysed scenarios, in a significant reduction of the generation value with increasing shares. Curtailment during hours of high production is an additional issue and may in practice reduce load factors and increase LCOE compared to reported values. This would be taken into account in the system analysis. By contrast, the output of wind plants is less correlated among individual units and thus its loss in value is less even as its share increases. At current levels of capacity, the impact of correlation is still limited in many markets, but it may rise if ambitious renewable targets are realised and relative shares increase. Technologies with high variable costs (such as high-flexibility open-cycle gas turbines), that produce only during a few hours with very high prices, provide on average a higher value (per unit of generation) to the system. Baseload plants, typically CCGTs (an exception is Europe, where they are mostly operating during hours with high residual load), coal and nuclear, that produce reliably over a high number of hours provide a value similar to the system average.

The results reported in Figure ES6 provide sample results of IEA’s VALCOE analysis for the European Union, China and the United States. While covering these large geographical regions, the model does not take into account grid bottlenecks or cross-border flows but instead assumes full integration across areas. Results thus potentially underestimate the flexibility constraints of future systems. The VALCOE measure provides an innovative approach to capture the complexities of system analysis in a single metric. Values depend not only on the overall share of variable renewables, but also on the costs of complementary resources such as energy storage or interconnections and the costs of competing technologies. Contrary to many other system analysis that simulate future system developments assuming long-run cost optimality, the scenario underlying the VALCOE calculations tries to replicate real-world systems. Future work will systematise and refine current results.

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).

Increasing shares of variable renewables in the energy mix increase the volatility of electricity prices and therefore improve the profitability of flexibility and balancing options. At the same time, sinking investment costs, for example for battery units, are already making short-term battery storage an economically attractive option in some niche applications (e.g. ancillary services markets). As more volatile electricity prices make inter-temporal arbitrage more attractive, storage could become an attractive alternative to peaking units such as open-cycle gas turbines, thus increasing its importance in the coming years. For the first time, a report of the Projected Costs of Generating Electricity series thus includes cost data for storage provided by participating countries.

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, followed   by 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. It highlights the 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’s Opportunities, the chapter highlights the critical role of the power sector  in 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.

This ninth edition of Projected Costs of Generating Electricity focuses on the cost of electricity generation from a wide set of technologies in a large range of countries. Inevitably, regional, national and local conditions have their importance. Nevertheless, the increasing competitiveness of low-carbon technologies for electricity generation remains the key insight of this report. This holds both for variable renewables such as wind and solar PV, as well as flexible low-carbon generators such as hydro and nuclear energy (including LTO). Even at a modest carbon price of USD 30 per tonne of CO₂, unmitigated coal is no longer competitive. Gas-fired electricity generation remains competitive in some markets, especially OECD North America, due to very low gas prices. CCUS would require considerably higher carbon prices than those seen in most markets today to become competitive.

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.