FOREWORD Renewables are becoming more and more competitive in the energy landscape. The data from the IRENA Renewable Cost Database shows cost declines continued in 2020, with the cost of electricity from utility-scale solar photovoltaics (PV) falling 7% year-on-year, offshore wind fell by 9%, onshore wind by 13% and that of concentrating solar power (CSP) by 16%. The decade 2010 to 2020 saw dramatic improvement in the competitiveness of solar and wind power technologies. Between 2010 and 2020, the cost of electricity from utility-scale solar photovoltaics (PV) fell 85%, followed by concentrating solar power (CSP; 68%), onshore wind (56%) and offshore wind (48%). The last decade has seen CSP, offshore wind and utility-scale solar PV all join onshore wind in the cost range for new capacity fired by fossil fuels, when calculated without the benefit of financial support. Indeed, the trend is not only one of renewables competing with fossil fuels, but significantly undercutting them.


The year 2020 was marked by the global pandemic and the subsequent economic and human toll it took. One bright spot, however, was the resilience of global renewable energy technology supply chains, despite some initial disruption. Another was the renewable power sector’s ability to adapt to the constraints created by the spread of the COVID-19 virus and continue to prosper. Indeed, despite fears that the pandemic would hit project completion rates, 2020 turned out to be another record year for renewable power generation capacity deployment. As costs continued to fall, renewable power generation remained the mainstay of new power sector capacity additions, with renewables increasingly becoming the default source of least-cost new power generation. Between 2000 and 2020, renewable power generation capacity worldwide increased 3.7-fold, from 754 gigawatts (GW) to 2 799 GW (IRENA, 2021a). With 261 GW of new renewable power generation capacity added in 2020, new renewable generation capacity additions were almost 50% higher than the 176 GW added in 2019 (IRENA, 2021a). In 2020, solar photovoltaic (PV) was once again the largest contributor to the total, with new capacity additions growing by over one-fifth (22%), to 127 GW of new capacity commissioned.1 Meanwhile, wind power capacity grew by 111 GW (with 105 GW of this growth in onshore wind power), which was almost twice as much as the 59 GW increase observed in 2019. Hydropower capacity increased by 20 GW, up from 12 GW added in 2019, while bioenergy power generation capacity increased by 2 GW, geothermal power by 164 MW and concentrating solar power (CSP) by 150 MW.

For newly commissioned projects, the global weighted-average LCOE of utility-scale solar PV fell by 85% between 2010 and 2020, from USD 0.381/kWh to USD 0.057/kWh (Figure 1.2), as global cumulative installed capacity of all solar PV (utility scale and rooftop) increased from 40 GW to 707 GW. This represented a precipitous decline, from being more than twice as costly as the most expensive fossil fuel-fired power generation option to being at the bottom of the range for new fossil fuel-fired capacity.8 This reduction has been primarily driven by declines in module prices – which have fallen by 93% since 2010, as module efficiency has improved and manufacturing has increasingly scaled-up and been optimised – and reductions in balance of system costs. As a result, the global weighted-average total installed cost of utility-scale solar PV fell by 85% between 2010 and 2020. Capacity factors have also risen, but predominantly due to the growth in new markets that saw a shift in the share of deployment to regions with better solar resources. Technology improvements that have reduced system losses have played a small but important role. The recent trend towards an increased use of trackers and bifacial modules – which increase yields for a given resource – is also having an impact. Unfortunately, the data is less clear on exactly what impact this is having on the global weighted-average capacity factor in 2020.

Annual values for the global weighted-average total installed costs, capacity factors and LCOEs are relatively volatile, given the relatively small number of projects added in some years. In recent times, the growth in new markets – both within Europe, where the first offshore wind markets developed, and globally have also added – more ‘noise’ to the data for any single year-on-year comparison. From 2010 to 2020, total installed costs fell by around 32%, while capacity factors increased by around one-fifth, from 38% in 2010 to 42% in 2019, before dropping back to 40% in 2020. The drop in the global weighted-average capacity factor for plant commissioned in 2020 was driven by China dominating new capacity additions. China’s offshore wind farms are still predominantly inter-tidal, or near shore, and in addition to not using the latest offshore wind turbine designs, these also have to contend with poorer quality wind resources. The installed costs and capacity factors of bioenergy for power, geothermal and sahydropower are highly project specific. As a result, and due to different cost structures in different markets, there can be significant year-to-year variability in global weighted-average values when deployment is relatively thin and the share of different countries/regions in new deployment varies significantly, year-to-year.

Despite lower operating costs, the competitiveness of existing coal-fired power plants in India and the United States remains precarious. With solar resources that are good-to-excellent in both countries, the 2021 weighted-average solar PV auction and PPA prices are very competitive, at around USD 33/MWh in India and USD 31/MWh in the United States. In the latter country, however, much depends on the location of deployment, given higher installed costs in California and on the East Coast. Both countries onshore wind auction and PPA prices for projects commissioning this year are competitive, at around USD 32/MWh in India and USD 37/MWh in the United States. The challenge that apportioning high fixed costs over ever-declining generation is brought into sharp relief in the United States, where, of the power plants analysed, 73% had annual capacity factors of less than 50%. The data presented here is indicative of the size of the opportunity that exists to accelerate the energy transition by retiring high-cost coal plants and replacing them with renewables. Assuming an average cost of USD 5/MWh for integration costs, Table 1.1 summarises the analysis for the four countries presented for 2021 in detail, as well as the results for the rest of the world.


Onshore wind turbine technology has advanced significantly over the past decade. Larger and more reliable turbines, along with higher hub-heights and larger rotor diameters, have combined to increase capacity factors. In addition to these technology improvements, total installed costs, operation and maintenance (O&M) costs, and LCOEs have been falling as a result of economies of scale, increased competitiveness and maturity of the sector. In 2020, onshore wind deployment was second only to solar photovoltaic (PV) and significantly higher than in 2019 due to a surge in projects commissioned in China. Today, virtually all onshore wind turbines are horizontal axis turbines, predominantly using three blades and with the blades “upwind”. The largest share of the total installed cost of a wind project is related to the wind turbines. Contracts for these typically include the towers, installation and delivery – except in China. Wind turbines now make up between 64% and 84% of the total installed costs of an onshore wind project (IRENA, 2018). The other major cost categories include installation, grid connection and development costs. The latter includes environmental impact assessment and other planning requirement costs, project costs, and land costs – with these representing the smallest share of total installed cost.

Brazil (71%) and China (63%). Of the countries covered in Figure 2.2, Canada and Brazil had the largest turbine rating and rotor diameters, respectively, on average in 2020. In 2020, India had the lowest turbine rating and the Japan had the lowest rotor diameter. Overall, in 2020 the country-level average turbine capacity ranged from 2.22 MW to 4.13 MW, and rotor diameter from 103 meters (m) to 134 m. Wind turbine prices reached their previous low between 2000 and 2002, with this followed by a sharp increase in prices. This was attributed to increases in commodity prices (particularly cement, copper, iron and steel), supply chain bottlenecks and improvements in turbine design, with larger and more efficient models introduced into the market. However, due to increased government renewable energy policy support for wind deployment, this period also coincided with a significant mismatch between high demand and tight supply, which enabled significantly higher margins for OEMs during this period. As the supply chain became deeper and more competitive and manufacturing capacity grew, these supply constraints eased and wind turbine prices peaked. Most markets experienced a peak between 2007 and 2010 and fell by between 44% and 78% by the end of 2020. Prices were in the range USD 700/kW to USD 910/kW in 2020 in most major markets, excluding China (Figure 2.3). The experience in China was one of a dramatic price fall from 1998 – when the wind turbine price was around USD 2 520/kW – to 2002. Prices then declined in an irregular, step-wise fashion to the point where the 2020 price was around an average of USD 540/kW, somewhat above 2019 levels due to tight supply given the surge in deployment in 2020.

The LCOE of an onshore wind farm is determined by the total installed costs, lifetime capacity factor, O&M costs, the economic lifetime of the project, and the cost of capital. While all of these factors are important in determining the LCOE of a project, some components have a larger impact. For instance, the cost of the turbine (including the towers) makes up the most significant component of total installed costs in an onshore wind power project. With no fuel costs, the capacity factor and cost of capital also have a significant impact on LCOE. The O&M costs, comprising fixed and variable components, made up from 10% to 30% of the LCOE in 2020 for the majority of projects. Reductions in O&M costs have been increasingly important in driving down LCOEs, as turbine price reductions are contributing less in absolute terms to cost reductions given their low levels today. Figure 2.9 presents the evolution of the LCOE (global weighted average and project level) of onshore wind between 1983 and 2019. Over that period, the global weightedaverage LCOE declined by 87%, from USD 0.311/kWh to USD 0.041/kWh. In 2010, the LCOE was USD 0.089/kWh, meaning there was a 54% decline over the decade to 2020. Consequently, onshore wind now increasingly competes with hydropower as the most competitive renewable technology, without financial support.


RECENT MARKET TRENDS By the end of 2020, over 707 GW of solar PV systems had been installed, worldwide. This represented more than 16-fold growth for the technology since 2010. About 127 GW of newly installed systems was commissioned during 2020 alone. These new capacity additions were the highest among all renewable energy technologies that year. Asia has led new solar PV installations since 2013. Following that trend, growth in 2020 was driven by continued new capacity additions in that region. Asia contributed about 60% of all new installations that year. Developments there were driven by China, where around two-thirds of all new Asian PV installations occurred. Meanwhile, after emerging as an important new market in 2019, Viet Nam’s new installations more than doubled between 2019 and 2020. The country installed more than 11.6 GW of PV during that year to become the second largest market in Asia. Japan, India and the Republic of Korea together contributed another 13.7 GW of new PV capacity during 2020. Historical markets outside Asia also continued to gain scale. Compared to 2019, new capacity in the United States doubled. During 2020, the United States, Australia and Germany together installed 24 GW, while Brazil and the Netherlands exceeded 3 GW each in new installations, creating combined growth of about a third of the total in 2019 (IRENA, 2021). Between 2013 and 2020, market-level module costs declined by between 49% (South Africa) and 71% (Brazil) for the markets for which historical data is available. Data for 2020 shows that a wide range of module costs still exists among the evaluated markets. Compared to 2019, however, the cost range has narrowed, in USD/W terms (from USD 0.32/W to USD 0.22/W). During 2020, the highest module cost was twice the lowest in the markets assessed (compared to 2.4 times higher in 2019). At the same time, module cost reductions of between 2% and 38% occurred in all assessed markets between 2019 and 2020. This points to the increasing cost maturity of a growing number of markets (Figure 3.2).

Recent disruption in the global module market balance dynamics and higher material costs are likely responsible for an uptick in module costs during early 2021. Costs for the first quarter of that year were between 1% and 9% higher, depending on the module type, than the 2020 module averages reported in Figure 3.2. This imbalance is related to increasing polysilicon prices and other supply and demand challenges in the upstream market. It is not yet known how the market will be affected for the full year. Capacity expansions already underway at the leading polysilicon manufacturers are likely to bring polysilicon pricing back to previous low levels. In the longer term, in addition, the continued improvement of efficiency, manufacturing optimisation and design innovation are expected to more than offset this temporary cost increase. Various factors are expected to continue to contribute to increasing solar PV technology’s competitiveness. For example, further adoption of bifacial technologies built from increasingly efficient cells is expected to continue. The average module efficiency of crystalline modules increased from 14.7% in 2010 to 20% in 2020. That rise was driven by a market shift from multycristalline more efficient monocrystalline products and by passivated emitter and rear cell (PERC) architectures having become the state-ofthe-art technology in modules. The efficiency of PERC modules is expected to grow towards 22% in the next few years, as it approaches its limits. In terms of cell architecture beyond PERC, likely candidates to drive efficiencies higher take two main approaches: first, by focusing on reducing losses at contacts (e.g. heterojunction [HJT] and tunnel oxide passivated contact [TOPCon] technology), or second, by focusing on moving metallisation to the rear of the cell to reduce front-side shading (e.g. interdigitated back contact [IBC] or cells). While solar PV has become a mature technology, regional cost variations do persist (Figure 3.5). These differences remain not only for the module and inverter cost components, but also for the BoS. At a global level, cost reductions for modules and inverters accounted for 61% of the global weighted-average total installed cost decline between 2010 and 2020. This means that BoS2 costs are therefore also an important contributor to declining global weighted-average total installed costs. Between 2010 and 2020, 13% of the global reduction came from lower installation costs, 7% from racking, 3% from other BoS hardware (e.g., cables, junction boxes, etc.) and 16% from a range of smaller categories. The reasons for BoS cost reductions relate to competitive pressures and increased installer experience, which has led to improved installation processes and soft development costs. BoS costs that decline proportionally with the area of the plant have also declined as module efficiencies have increased.

In 2020, the country average for the total installed costs of utility scale solar PV for the countries reported in Figure 3.5 ranged from a low of USD 596/kW in India to a high of USD 1 889/kW in the Russian Federation. The highest cost average was about three-and-ahalf times more than the lowest during 2019, whereas in 2020 this ratio declined to about 3.2. This points to the convergence of installed costs in major markets, in recent years. On average, in 2020, BoS costs (excluding inverters) made up about 65% of total system costs in the countries in Figure 3.5. During 2016, they made up about half of the total system cost. This increased share highlights the increasing importance of BoS costs, as module and inverter costs continue to come down. In 2020, total BoS costs ranged from a low of 55% in China to a high of 80% in the Russian Federation. Overall, soft cost categories for the countries evaluated made up around 35% of total BoS costs and, on average, 23% of the total installed costs. In 2016, these values were a third and 17%, respectively. A better understanding of cost component differences amongst individual markets is crucial to understanding how to unlock further cost reduction potential. Obtaining comparable cost breakdown data, however, is often challenging. The difficulties relate
to differences in the scale, activity and data availability of markets. Despite this, IRENA has expanded its coverage of this type of data, collecting primary cost breakdown information for additional utility-scale markets.


TOTAL INSTALLED COSTS Compared to onshore wind, offshore wind farms have higher total installed costs. Installing and operating wind turbines in the harsh marine environment offshore increases costs. Planning and project development costs are higher and lead times longer as a result. Data must be collected on seabed characteristics and the site locations for the offshore wind resource, while permitting and environmental consents are often more complex and time consuming. Logistical costs are higher the farther the project is from a suitable port, while greater water depths require more expensive foundations. Offshore wind, however, has the advantage of economies of scale, meaning that some of these costs are not disproportionately higher than those for onshore wind. At the same time, the higher capacity factors offshore and the more stable wind output (due to higher average wind speeds and reduced wind shear and turbulence), which also coincides with winter demand peaks in Europe, ensure offshore wind output is of higher value to the electricity system than onshore wind. The promise of offshore wind has always been evident and, in the last few years, it has started to realise its potential from scaling. Between 2010 and 2020, the average offshore wind project size increased by 121%, from 136 MW to 301 MW. There are currently projects that began to be deployed in 2020 and beyond that have capacities exceeding 1 GW. The global weighted-average total installed cost of offshore wind farms increased from around USD 2 592/kW (kilowatts) in 2000 to over USD 5 500/kW 2008, and bounced around the USD 5 000/kW for the period 2008 to 2015, as projects moved farther from shore and into deeper waters (Figure 4.4). The global weighted-average total installed cost began to decline after 2015, falling relatively rapidly to USD 3 185/kW in 2020.

CONCENTRATING SOLAR POWER Concentrating solar power (CSP) systems work in areas with high direct normal irradiance (DNI) by concentrating the sun’s rays using mirrors to create heat. In most systems today, the heat created from concentrating the sun’s energy is transferred to a heat transfer medium, typically a thermal oil or molten salt. Electricity is then generated through a thermodynamic cycle, for example using the heat transfer fluid to create steam and then generate electricity, as in conventional Rankine-cycle thermal power plants. CSP plants today almost exclusively include low-cost thermal storage systems to decouple generation from the sun. Indeed, this is also usually the route to lowest-cost and highest value electricity. Most commonly, a two-tank, molten salt storage system is used, but designs vary. It is possible to classify CSP systems according to the mechanism by which solar collectors concentrate solar irradiation, either ‘line concentrating’ or ‘point concentrating’ varieties. These terms refer to the arrangement of the concentrating mirrors. Today, most existing systems use linear concentrating systems called parabolic trough collectors (PTCs). Typically, single PTCs consist of a holding structure with individual line focusing curved mirrors, a heat receiver tube and a foundation with pylons. The collectors concentrate the solar radiation along the heat receiver tube (also known as absorber), a thermally efficient component placed in the collector’s focal line. Various PTCs are traditionally connected in ‘loops’ through which the heat transfer medium circulates to achieve scale. Line concentrating systems rely on single-axis trackers to maintain energy absorption across the day increasing the yield by generating favourable incidence angles of the of the sun’s rays on the aperture area of the collector. Specific PTC configurations must account for the solar resources at the location and the technical characteristics of the concentrators and heat transfer fluid. That fluid is passed through a heat exchange system to produce superheated steam, which drives a conventional Rankine-cycle turbine to generate electricity. of storage. This is 2.2 times larger than the average value for projects commissioned between 2010 and 2014 and is continuing to grow. For instance, the weighted-average storage level for projects commissioned in 2020 was 11.7 hours, which is 63% higher than those of 2018-2019 (SolarPACES, 2021). The capital costs for CSP projects commissioned in 2020 for which cost data is available in the IRENA Renewable Cost Database ranged between USD 4 295/kW and USD 5 154/kW (Figure 5.2).

HYDROPOWER Hydropower is both mature and reliable and is also the most widely deployed renewable generation technology, even though its share of global renewable energy capacity has been slowly declining. Indeed, hydropower’s share fell from 72% in 2010 (881 GW) to 41% in 2020, although by the end of that year, total global installed hydropower capacity (excluding pumped hydro) had risen to 1 153 GW. Hydropower provides a low-cost source of electricity and, if the plant includes reservoir storage, also provides a source of flexibility. This enables the plant to provide flexibility services, such as frequency response, black start capability and spinning reserves. This, in turn, increases plant viability by increasing asset owner revenue streams, while enabling better integration of variable renewable energy sources to meet decarbonisation targets. In addition to the grid flexibility services hydropower can provide, it can also store energy over weeks, months, seasons or even years, depending on the size of the reservoir. In addition, hydropower projects combine energy and water supply services. These can include irrigation schemes, municipal water supply, drought management, navigation and recreation, and flood control – all of which provide local socio-economic benefits. Indeed, in some cases the hydropower capability is developed because of an existing need to manage river flows, with hydropower incorporated into the design.


INTRODUCTION The best geothermal resources are those found in active geothermal areas on or near the surface of the Earth’s crust. These can be accessed at lower cost than the evenly distributed heat available at greater depths anywhere on the planet. By drilling into the earth’s surface, the naturally occurring steam or hot water in active geothermal areas can be easily accessed and used to generate electricity in steam turbines. Given the somewhat unique nature of geothermal resources, geothermal power generation is very different in nature to other renewable power generation technologies. Indeed, developing a geothermal project presents a unique set of challenges when it comes to assessing the resource and how the reservoir will react once production starts. Sub-surface resource assessments are expensive to conduct and need to be confirmed by test wells that allow developers to build models of the reservoir’s extent and flow. Much, however, will remain unknown about how the reservoir will perform and how best to manage it over the operational life of the project.


BIOENERGY FOR POWER Power generation from bioenergy can come from a wide range of feedstocks. It can also use a variety of different combustion technologies, running from mature, commercially available varieties with long track records and a wide range of suppliers, to less mature but innovative systems. The latter category includes atmospheric biomass gasification and pyrolysis, technologies that are still largely at the developmental stage but are now being tried out on a commercial scale. Mature technologies include: direct combustion in stoker boilers; low-percentage co-firing; anaerobic digestion; municipal solid waste incineration; landfill gas; and combined heat and power (CHP). In order to analyse the use of biomass power generation, it is important to consider three main factors: feedstock type and supply; the conversion process; and the power generation technology. Although the availability of feedstock is one of the main elements for the economic success of biomass projects, this report’s analysis focuses on the costs of power generation technologies and their economics, while only briefly discussing delivered feedstock costs.


Solar thermal technologies are used in all regions of the world to provide low and medium temperature heat in industry and buildings. Solar thermal technologies are highly modular and can be installed on the rooftops of individual buildings for residential use, or in hospitals or hotels. They can also be found in large, MW-scale ground-mounted systems in industry, agriculture and district heating networks. The market for solar thermal is still at an early stage of development, but at least 120 large-scale heat projects were added in 2020 in the commercial and industrial sectors. These feed renewable heat into district heating networks, or supply heat to processes in the manufacturing sector. Compared to what is needed to achieve the Paris Agreement goals, deployment rates remain woefully inadequate. For instance, IRENA’s 1.5°C pathway requires global solar thermal capacity to increase from around 4 gigawatts thermal (GWth) in 2018 to 890 GWth in 2030 and 1 290 GWth in 2050. Modest growth – total solar thermal heat capacity in Europe grew by only 3% in 2020 (Solar Heat Europe/ESTIF, 2021) – is therefore insufficient. Like many of the technologies necessary for decarbonising the building and industrial sectors, solar thermal is typically held back by the absence of co-ordinated and sustained policy support to decarbonise heat. The result of erratic and inconsistent support levels over time, has been insufficient market growth and the subsequent lack of scale that would otherwise stem from more consistent policy support and allow lower costs.

Denmark leads the world for total district heating capacity in operation, with more than 1 GWth at the end of 2020. Around 120 villages, towns and cities use solar heat in their municipality-owned district heating networks. The total installed cost of district heating scale solar heat in Denmark fell from a weighted average of USD 573/kW in 2010 to USD 409/kW in 2019. This represents a learning rate for the period of around 17% – slightly higher than that of onshore wind for the period 2010 to 2020. These cost reductions have made solar thermal heating systems a competitive source of heat for district heating, as the weighted-average levelised cost of heat (LCOHEAT) fell from USD 0.066/kWh in 2010 to USD 0.045/kWh in 2019 (Figure 9.1).

In Austria, total installed costs fell by 55% between 2013 and 2020. In Germany, they fell by 45% between 2014 and 2020, while in Mexico, they fell by 17% between 2010 and 2020 Data for 2020 and 2021 is still sparse, while care must be taken interpreting the data – notably for Austria, where only a handful of data points is available. By 2020, however, total installed costs had converged somewhat, with, on average, larger projects in Austria having a slightly lower weighted average in those two years than in Germany and Mexico. When we come to LCOHEAT, however, the superior solar resources available in Mexico become readily apparent, as the weighted-average LCOHEAT of the solar thermal plants in Mexico in 2020 was USD 0.039/kWh. The increase in Germany in 2020 for LCOHEAT is due to one outlier, with very high installed costs, while the decline for Austria in the weighted-average LCOHEAT between 2018 and 2020 is predominantly due to the much larger average size of systems deployed in the latter period, compared to the period prior to 2018. This is a graphic illustration of the benefits of economies of scale.


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