IEA (2020), Renewables 2020, IEA, Paris https://www.iea.org/reports/renewables-2020
Global solar PV capacity additions are expected to reach nearly 107 GW in 2020 in the main case, representing stable growth from 2019 (this forecast has been revised up by 18% from the market report update published in May). IEA monthly deployment data indicate that construction activity for utility-scale projects slowed from March through April, but rapidly regained speed in mid-May.
Deployment of distributed PV applications remains sluggish in large markets such as China and the United States, although activity in most European markets, Australia and Brazil has not been hampered significantly. Still, the share of distributed applications in total PV deployment is expected to decline to 37% this year, the lowest since 2017.
In 2020, utility-scale additions will increase nearly 3% owing to record additions in the United States. China is expected to construct over 33% more PV capacity than in 2019, as developers rush to complete projects before the phaseout of subsidies. Additions in India decline for the second straight year as DISCOMs’ financial health challenges persist and Covid‑19 measures inhibit construction activity.
Global distributed PV additions are forecast to be 8% lower in 2020 than in 2019 as the current economic uncertainty shifts the financial priorities of both individuals and small/medium-sized enterprises in some countries. Fewer distributed PV additions in key markets such as the United States, the European Union, India and Japan mark the global trend. Conversely, generous policy incentives drive a residential market boom in China and spur commercial market activity in Brazil despite the pandemic.
In the accelerated case, global solar PV additions could be more than 120 GW in 2020, 16% higher than in the main case. China and the United States account for the largest portion of extra accelerated-case capacity because developers in both countries usually commission projects in the last quarter of the year, due to policy schedules. China’s historical last-quarter deployment (which ranges from 7 GW to 15 GW) does, however, introduce a major portion of 2020 PV forecast uncertainty.
Another record for global solar PV additions is anticipated for 2021, with nearly 117 GW installed – a nearly 10% rise from 2020. The increase results from a strong rebound in utility-scale plants outside of China, where the phaseout of subsidies curbs PV expansion. Utility-scale project development rebounds in India and key EU markets (France and Germany) to meet auction-commissioning deadlines.
With Chinese developers shifting investments from distributed to larger utility-scale projects as subsidies end, distributed PV growth does not fully return to the 2019 level. In 2022, global PV additions continue to expand to almost 120 GW. Although there is uncertainty concerning the new post-subsidy support scheme in China, PV deployment will gain speed in Europe and the United States thanks to increasing competitiveness and continuous policy support.
In the accelerated case, annual additions could reach over 142 GW in 2021 and 149 GW in 2022 with:
- A smooth policy transition to ensure investor confidence in China.
- Faster distributed PV recovery in the United States and Europe.
- Rapid implementation of auctions and grid connections in India and Latin America.
- Timely commissioning of auctioned capacities in the Middle East and Africa.
- Elimination of policy uncertainties and administrative challenges in ASEAN countries.
Global annual solar PV additions are expected to accelerate during 2023‑25, owing to faster recovery of distributed PV applications as the global economy improves. Outside of government support schemes, market drivers such as corporate PPAs and bilateral contracts are forecast to support PV expansion globally. Potential in the ASEAN region remains largely untapped due to administrative and regulatory challenges, while the lack of policy certainty and infrastructure is hampering regional growth.
Global PV expansion after 2022 is expected to accelerate even more quickly, owing to continuous policy support and cost reductions. The distributed PV segment resumes growth during 2023-25 as global economic recovery supports faster adoption of commercial and residential systems. The higher potential for total PV in the accelerated case compared with the main case is significant, with the possibility of annual capacity additions averaging almost 165 GW during 2023‑25.
Solar PV capacity additions are expected to increase 33% in 2020 from 2019. China’s PV growth slowed in 2018 and 2019 because the government temporarily froze PV subsidy allocations and announced the transition to competitive auctions in 2018. Growth resumed this year, however, with the commissioning of projects awarded in the country’s competitive auctions held in July 2019 and June 2020 – before all PV subsidies are phased out at the end of 2020 (except for residential applications).
Overall, the policy transition to auctions has reduced the appetite for commercial PV applications, which accounted for almost half of PV growth in 2018. Conversely, the popularity of residential PV installations is booming thanks to continuous financial support through the end of 2021.
In its second auction in July 2020, China awarded almost 26 GW of solar PV projects – more than in the first one – as the average contract price drop of 18% spurred greater contracted capacity even though the subsidy budget had been cut by half.
Two key trends that have emerged from the auction will shape China’s future solar PV market. First, commercial solar PV developers showed limited interest in the auction because the investment priorities of small and medium-sized enterprises have shifted with the Covid‑19 crisis. Second, the competitive process has pushed developers to focus on larger projects in order to benefit from economies of scale and achieve lower bids.
In the 2019 auction, projects with a capacity of 1-5 MW accounted for a significant majority of awarded capacity, while the average project size was almost three times higher in the 2020 auction. Projects with winning bids are forecast to come online in 2020 and 2021 while residential solar PV additions are expected to range from 9 GW to 10 GW, almost double the 2019 level, as developers rush to benefit from the generous FiT scheme that will end in 2021.
After subsidies are phased out in 2020/21 and the 13th Five-Year Plan on Renewables expires, capacity additions in 2022 are expected to decline due to uncertainties over the new policy scheme and targets in the upcoming 14th Five-Year Plan. An emerging development schedule shows plans for a pipeline of “grid parity” projects under 20-year contracts at administratively set provincial power prices. Although the government approved 29 GW of these projects in July 2020, many are expected to be cancelled or postponed due to increasing financing challenges caused by the Covid‑19 crisis and a lack of penalties for non-completion.
Beyond 2022, growth in annual additions is projected to resume, averaging 40‑50 GW through 2025. In the absence of subsidies, continuous PV cost declines will remain the key driver for expansion. The large difference between the main and accelerated cases reflects uncertainty over the new policy scheme after the phaseout of subsidies.
Although implementation of state-level renewable portfolio standards began this year, the current design provides only limited incentives for solar PV projects, especially rooftop distributed PV. The smooth interaction between newly introduced provincial spot electricity and green certificate markets, along with the implementation of the RPS scheme, will be key for faster solar PV project expansion.
Unprecedented US solar PV expansion of almost 17 GW is forecast for 2020, the highest annual increase to date. Growth is mostly in utility-scale projects, with 3.9 GW more additions than in 2019, which will more than offset the decline forecast for the distributed segment.
Numerous utility-scale projects were already under development at the beginning of 2020, and construction has continued relatively unaffected by shelter-in-place orders because many states deem construction an essential service. While some developers have reported delays or pauses in construction, newly installed capacity increased 30% from the first to the second quarter of 2020. Growth is expected to remain strong in the second half of the year, as remaining social-distancing measures are assumed to have very little effect on the considerable 13.6 GW under construction.
Meanwhile, distributed PV growth is expected to contract in 2020 because permitting and interconnection approval delays have been holding up development of some commercial systems. A slight contraction is also expected in the residential segment as shelter-in-place orders have limited the number of in-person sales. As a result, the number of new distributed PV installations dropped 23% from Q1 to Q2 (SEIA, 2020). The annual decline is expected to be less, however (8% down from 2019), as the transition to online processes for sales, consultation, and permitting indicates increased development activity during the second half of the year.
Annual additions are expected to rise in 2021 and continue to increase in 2022 owing to a large portfolio of contracted projects established on the basis of two main drivers. The first impetus remains RPSs, regulations that obligate retailers to supply a percentage of electricity from renewable energy. These have historically been a key driver for growth, and about half of the country’s planned projects are in the 30 states that have them. The largest project slates are in states that have raised their targets in recent years (e.g. California, Nevada and New York), but more projects have also sprung up in Virginia, the most recent state to introduce an RPS in April 2020 that mandates 100% renewable electricity by 2050.
The second growth stimulus is economic attractiveness. An increasing share of expansion will be in states where RPSs have already been met or are non-existent, such as in the Southeast and Southwest. For instance, falling costs, investment tax credits, and excellent resource potential have launched numerous large utility projects in Texas, Florida and Georgia, where land availability is not a constraint. In addition, the economic attractiveness of solar-plus-storage is making utility-scale installations more appealing in some western states.
This forecast assumes these projects have already secured financing and, as such, are not at risk of cancellation during a weaker economic climate. Nevertheless, tighter financing conditions for new projects do pose a risk. Tax equity, the main source of financing for utility PV projects, is reported to have shrunk since March 2020 as a result of the lockdown, and project financing is being delayed until 2021 due to economic uncertainty (BNEF, 2020a).
If fewer projects secure financing in 2020/21, capacity expansion in 2021/22 will be lower. The more cautious lending environment will also impact the riskiest projects, especially those with a merchant tail (a period in which energy is being sold directly into the market).
After 2022, utility installation growth is expected to slow slightly due to a step-down in the Investment Tax Credit (ITC) to 10% in 2022. In addition, uncertainty over the business case in a weaker economic environment with potentially lower power prices and less demand may reduce corporate PPA demand.
Nonetheless, average annual growth during 2023-25 is still expected to be higher than in the years preceding the Covid‑19 pandemic, owing to both ambitious state-level RPSs and utilities’ self-mandated targets in states lacking an RPS, particularly in the Southeast. In the past year, several large state utilities announced emissions reduction targets for 2030 and 2050, and released integrated resource plans in which solar PV plays a key role (SACE, 2020).
For distributed PV, annual additions are forecast to increase in 2021 in anticipation of the phaseout of the residential ITC, and to subsequently decline in 2022. Also contributing to the expected contraction in 2022 is uncertainty over how attractive self-consumption will be for the commercial segment in a weaker economic climate. Less energy demand, company budget reprioritisations and tighter financing conditions could discourage new investments.
Yet, a rebound in average annual growth is expected between 2023 and 2025 as improved consumer confidence supported by favourable net-metering rules stimulates the residential sector, and new community solar initiatives help encourage the commercial segment.
Average annual growth could higher in the accelerated case. For utility-scale, this would be supported by an increase in corporate buying and utility procurement. For distributed PV, these would require faster declines in soft costs, one of the largest costs for residential PV, and more rapid permitting and grid connection in areas where there are backlogs for commercial PV.
India’s solar PV capacity additions are forecast to be one-third lower in 2020 than in 2019. In the first half of 2020, new PV capacity installations were 70% below average first-half growth of the previous three years. This drop resulted from a combination of Covid‑19-related supply chain disruptions and construction slow-downs, as well as increased macroeconomic risks.
Consequently, compared with our previous update in May, this forecast anticipates 19% fewer additions in 2020. A rebound in PV deployment is expected for 2021 and 2022, with capacity additions exceeding the 2019 level as delayed and new projects become operational.
The Covid‑19 crisis has compromised distribution companies’ (DISCOMs’) financial viability. The financial instability of many DISCOMs leads to delayed payments to generators, decreasing the profitability of existing projects and raising the level of risk perceived by potential developers and financial institutions.
According to the Ministry of Power’s annual financial performance ratings, one-third of electricity sales in 2018 came from DISCOMs rated below B+ on a six-grade scale ranging from C to A+. New PV installations in networks managed by utilities with low grades will likely face greater obstacles than those overseen by healthier DISCOMs. In addition, distressed DISCOMs view the development of rooftop PV as an additional challenge, as higher self-consumption reduces revenues from their most profitable commercial customers.
Policies to improve DISCOMs’ financial health through the UDAY scheme introduced in 2015 have been only partially successful, and overdue payments to generators began increasing again in 2018. In fact, from January to June 2020, total overdue payments owed by DISCOMs rose 28% for all electricity generators and 10% for renewable electricity plants.
In May 2020, India’s government announced an extensive loan programme to reduce overdue amounts owed to generators. Although it is expected to provide important relief to renewable energy developers, a structural solution is needed to ensure the sustainability of DISCOMs to achieve faster PV growth.
The main catalyst for utility-scale PV deployment is reverse-bid auctions. The switch from state-level to central auctions continued in 2020, as the latter provides more payment security and attracts greater competition. Despite Covid‑19 disruptions, India had auctioned 8.2 GW of new PV capacity by the end of September 2020 – more than in the same period last year. Tariffs awarded in 2020 were 4% lower on average than in 2019, registering among the lowest in the world. In addition, the government awarded a record 12 GW of PV capacity linked with 3 GW of PV module manufacturing. New types of wind-solar-storage hybrid auctions were also held this year, making these systems competitive with existing coal-fired generators in many states.
Low bid ceilings, however, have been one of the main causes of undersubscription in many past auctions. Therefore, in March 2020 the government announced that future auctions will not contain ceilings, allowing developers to fully reflect changes in the economic environment in their bids and secure sustainable revenues.
Despite auction design improvements, transmission grid bottlenecks and land acquisition challenges persist. The Indian government is taking action to overcome these obstacles, mainly through the Green Energy Corridor and Solar Parks projects, but faster development is needed to reach ambitious national capacity targets by 2022.
Distributed PV deployment in the commercial and residential sectors is also expected to fall due to Covid‑19 disruptions. In our forecast, distributed PV capacity additions are 58% lower in 2020 than in 2019, and are not expected to exceed the 2019 level before 2022, as demand for installations likely remains subdued due to uncertainty regarding the macroeconomic environment and employment.
Because DISCOMs in better financial health usually support rooftop PV project deployment more eagerly, states with higher-graded utilities are more likely to meet their rooftop PV targets. Faster rooftop PV expansion requires that DISCOMs financial challenges be resolved to ensure their active co‑operation in implementing state net-metering policies, and that affordable financing be made available.
A positive development is that new business models have emerged for DISCOMs to benefit from distributed PV deployment. In addition, demand aggregation models to streamline borrowing are being developed, but the reach of such programmes remains limited.
The forecast predicts stable annual capacity addition growth after 2022, resulting from declining PV installation costs, the continuation of auction programmes and gradually improving conditions for distributed PV development. Annual capacity increases during 2023-25 could average 13 GW to 18 GW between the main and accelerated cases. Achieving higher deployment will require that DISCOMs financial stability improves, the full potential of distributed PV is unlocked, transmission grid constraints are eliminated and land acquisition becomes simpler.
Japan’s solar PV market is expected to contract slightly (by 9%) in 2020 compared with 2019. Capacity additions are mostly driven by different commissioning deadlines for FiT-approved PV projects in each of the segments, while the impact of the Covid‑19 crisis on solar PV construction activity has been minimal.
Utility-scale installations are most affected by commissioning deadlines because many FiT-approved projects need to be commissioned in 2020 and 2021 to maintain the previously agreed prices and support periods, resulting in strong growth in these years. Fewer FiT-based projects in 2022, however, is expected to reduce utility-scale PV additions, with only a minimal contribution from auctions.
Auction-based capacity is low relative to new FiT approvals, with previous auction rounds undersubscribed. For commercial solar PV, a rush to complete FiT-approved projects by 2022 due to commissioning deadlines, and additional investment subsidies for PV and storage as part of Covid‑19 stimulus are expected to boost growth over 2020-22.
Japanese PV additions are expected to contract starting in 2022, mainly due to phaseout of the generous FiT scheme for large-scale projects and undersubscribed capacity in previous auctions. The government has approved introduction of a FIP scheme for large solar PV projects. The new policy aims to reduce financial burden, encouraging PV plants to participate in electricity markets to facilitate their system integration and providing a stable long-term revenue stream for developers. However, details regarding the maximum size of eligible projects, ceiling price and the competitive selection process have not yet been decided and remain a forecast uncertainty beyond 2022.
Smaller commercial installations will continue to be eligible for FiT-based remuneration, but they are likely to face stricter rules such as a self-consumption requirement of at least 30%.
Solar PV growth during 2023-25 could be one-fourth higher in the accelerated case, with more attractive FIP remuneration and further cost declines, unlocking of the potential of other revenue streams such as PPAs, and continuation of the FiT scheme for medium-sized commercial installations.
Solar PV capacity additions in the ASEAN region are forecast to reach 2.8 GW in 2020, 57% lower than last year when developers in Viet Nam rushed to complete projects before the announced FiT phase-out. In other ASEAN countries, PV development remains slow in 2020 due to limited policy support.
From 2021 onwards, however, a decrease in new installations in Viet Nam following its FiT phase-out should be mostly offset by faster growth in other ASEAN countries. Utility-scale projects account for the majority of new additions in the region due to limited support for distributed applications. However, the share of commercial and residential installations in total investments is likely to increase over 2023-25 thanks to an improved regulatory environment and rising economic attractiveness.
In Viet Nam, PV capacity additions are expected to decline 65% to 1.9 GW in 2020 due to phase-out of the generous FiT in June 2019. Although a government decision to extend the commissioning deadline for previously approved projects to the end of 2020 will keep annual additions relatively strong, workforce shortages and supply chain disruptions due to the Covid‑19 crisis – combined with grid connection challenges – could delay the completion of many approved projects to 2021.
In addition, transition from the FiT to an auction scheme is expected to further slow annual growth in 2022. Distributed PV deployment should accelerate during the forecast period, stimulated by decreasing costs and new business models, including on-site private PPAs and roof-space renting introduced in 2020.
During 2023‑25, auctions and distributed PV are expected to boost capacity additions in Viet Nam. In the accelerated case, annual additions beyond 2022 could reach 2.5 GW assuming faster grid expansion, a smooth transition to the new auction scheme and further facilitation of private PPAs through standard contracts and more risk-sharing between developers and off-takers.
Indonesia’s PV growth is expected to remain limited in the 2020-22 period. Regulatory challenges persist, hampering the acceleration of renewable energy deployment. The main barrier remains a low tariff for renewable energy generators, set below the average purchase price of electricity. This low tariff and relatively high installation costs reduce the economic attractiveness of PV projects.
However, more supportive regulations are being introduced that could accelerate growth beyond 2022. In February 2020, the requirement to build all projects under the Build, Own, Operate and Transfer scheme was lifted, increasing bankability. Plus, priority dispatch for renewable generators was introduced and the process of signing PPAs with the central off-taker was simplified. In addition, a new regulation that includes a FiT for smaller installations and auctions for larger systems is under government consideration.
The 2020 forecast for the Philippines assumes 0.2 GW of new PV installations, similar to the 2019 level. Since the beginning of 2020, an RPS with auctions has been introduced to increase the share of renewables in total electricity consumption from 21% in 2019 to 35% in 2030. The RPS is expected to drive PV growth, with annual deployment reaching almost 0.5 GW through 2022 and a further increase to 0.8 GW during 2023-25.
In Thailand, PV capacity additions are expected to remain between 0.1 GW and 0.3 GW per year over 2020-22 in the absence of new policies. Current support policies include annual contracting of 0.1 GW of residential rooftop PV for net-metering, but interest remains limited due to insufficient remuneration for excess generation.
The government is also encouraging floating PV deployment, with the first auction for 45 MW already awarded and more capacity planned. Without additional policy support, however, revenues for renewable energy generators in most cases remain too low to ensure significant acceleration.
PV additions of just over 3.5 GW are expected in 2020 – over 30% less than in 2019. This decline results mostly from 50% lower utility-scale PV additions, as delays in grid connection approvals and new operational requirements have lowered project outputs, making the business case for multiple PV projects less attractive and reducing investor confidence.
In addition, Australia has already met its 2020 Renewable Energy Target, resulting in an oversupply of generation certificates, which reduces revenues and undermines the business case for new developments. Consequently, utility-scale additions are expected to shrink further in 2021 and 2022.
For distributed PV applications, installations continue to be encouraged by both the small-scale certificate programme and state-level FiT schemes (buy-back tariffs for distributed PV exports) offered by both utilities and retailors. The impact of the Covid‑19 crisis remains limited, as monthly installations in 2020 already outpaced those of 2019, with additions expected to reach over 2 GW this year.
However, declining wholesale prices (which guide benchmark FiT rates in many states), market saturation in some states (e.g. New South Wales and Victoria), and lower values of small-scale certificates all challenge faster growth in 2021 and 2022.
Moderate gains in utility-scale and distributed PV installations will begin in 2023 as both the small- and large-scale certificate programmes continue through 2030, and as improving grid conditions from planned new investments help reduce connection and curtailment challenges. However, with the projected generation target of the LRET programme having been met already, PV projects will have to rely on merchant installations, corporate PPAs or state-level incentives, such as the New South Wales Renewable Energy Zones.
Net PV additions are expected to reach 16.5 GW in 2020, a 4% decline relative to 2019, which had been an exceptional year as Spain added 4 GW of utility-scale PV to meet support deadlines. Excluding Spain, where additions in 2020 have halved, Europe’s annual additions are set to grow by 13% in 2020 and reach their highest level since 2012 despite lockdowns and social distancing measures. Most of the increase is driven by utility-scale deployment from auctions in Germany, France and Poland. Higher growth also stems from the increasing attractiveness of net-metering in Turkey, Poland and the Netherlands.
After 2020, net additions in Europe are forecast to increase steadily from 21 GW in 2021 to an average of 25 GW per year between 2023 and 2025. This trend is largely underpinned by an increase in policy support to meet the European Union’s 2030 renewable energy target of 32% under the Renewable Energy Directive. EU member states were required to submit their final 2030 renewable energy targets by the end of 2019, accompanied by plans to reach them, and several countries have already introduced or drafted national legislation to implement them.
Utility-scale growth plays an increasingly important role over the forecast period, with its share rising from 41% in 2021 to an average of 55% annually by 2023‑25, owing to an increase in competitive auctions. Over the past year, legislation to expand and extend support has either been passed or introduced to reach new 2030 targets in major markets. Italy introduced auction schemes in 2019 and Poland continued to raise auction volumes while in 2020 Spain announced plans to resume tenders and Germany proposed to increase and extend annual auction volumes.
Distributed PV continues to increase gradually in Europe during 2021-25, driven by steady growth in the commercial segment from self-consumption, net metering and, in some cases, auctions. However, the impact of support-scheme changes on large commercial systems in large markets is a forecast uncertainty. In an effort to stimulate growth while balancing support costs, several countries are modifying their policy designs by changing size eligibility and mechanism to determine remuneration levels. Germany, the largest commercial market, proposes changing support for large commercial rooftop systems from FIPs to competitive auctions, while France has decided to move support for self-consumption in the segment back to administratively-set tariffs after auctions were under subscribed.
Commercial PV is also remunerated by auctions in the Netherlands, but new auction design rules under the SDE++ scheme raise concerns about its competitiveness, as now commercial PV systems must compete with non-electricity technologies. Residential PV in Europe maintains steady growth, led by self-consumption in Germany and net metering in the Netherlands and Poland.
A number of factors could accelerate PV growth in Europe. Utility-scale capacity increases could be 25% higher on average during 2023-25 with clarity over auction design proposals, streamlined permitting and licensing to minimise under-subscription in auctions, and more attractive economics for corporate PPAs. Maintaining self-consumption support for distributed systems could boost annual growth by 37%.
Solar PV additions in 2020 are forecast to increase 8% (to 4.3 GW) compared with 2019 as the result of a robust development slate of projects from competitive auctions and the continued attractiveness of self-consumption.
Despite lockdown measures, utility-scale additions more than doubled in the first half of 2020 compared with 2019, and additions in the residential segment expanded by 90% (Bundesnetzagentur, 2020). The utility-scale increase results from the commissioning of capacity from special auctions held in 2019 (an amendment to the Renewable Energy Act in 2018 introduced an additional 4 GW of auctions during 2019-21 to accelerate progress towards climate goals). The residential increase in installations is driven by falling system costs and high electricity prices.
However, two main uncertainties affect growth potential for the last quarter of 2020. The first is the risk of delays in utility-scale project development due to social-distancing measures related to Covid‑19. The second is the impact of extension of support for distributed PV, a major motivator for the commercial segment.
Remuneration for excess generation was set to expire once cumulative PV capacity reached 52 GW, a threshold expected to be attained by mid-2020. The installation pace therefore increased in the months leading up to the looming expiration; however, the government removed the cap in May 2020 and extended support, and installations have since declined. Total installed distributed PV capacity had reached an estimated 2.4 GW by August 2020, and it remains to be seen how much the increased visibility over support will affect fourth-quarter deployment.
Additions are forecast to expand in 2021 owing to a strong increase in utility-scale projects from the additional 4 GW of auctions. Also supporting the sharp increase is additional capacity from the joint PV-wind auctions and the commissioning of unsubsidised projects (corporate PPAs and bilateral contracts with utilities). Five joint solar-PV auctions totalling 1 GW have been held since 2018, and all was awarded to solar PV with average prices ranging from EUR 47/MWh to EUR 57/MWh.
PV additions are expected to decline in 2022, largely due to a contraction in distributed PV stemming from a proposed reform to the Renewable Energy Act (the EEG 2021). The draft, released in September 2020, proposes that rooftop systems greater than 500 kW compete in competitive auctions capped at 200‑400 MW per year starting in 2021, which is substantially lower than the 1 GW deployed in 2019 under the self-consumption scheme.
Utility-scale growth during 2023‑25 is largely driven by the proposed EEG 2021. In June 2020, the government raised the 2030 target for the share of renewable electricity from 50% to 65%, and to meet this goal, in September 2020 the government proposed to increase the 2030 PV capacity target to 100 GW. This proposal raises annual utility-scale auction volumes from 600 MW to 1.9-2.8 GW.
For distributed PV, annual additions average 2.6 GW during 2023-25, significantly below growth in 2019 and 2020 due to limits on the amount of rooftop systems over 500 kW eligible for support. However, attractive economics for self-consumption with excess remuneration continue to drive medium- and small-scale commercial growth. For residential installations, the main case expects a steady increase, supported by higher demand from electric cars and heat pumps.
The main case reflects the draft EEG 2021 proposal, which still had to be passed by Germany’s parliament at the time of writing. Total average annual growth could be 43% higher between 2023 and 2025 with stronger distributed PV deployment. This would require the final EEG 2021 Act to maintain self-consumption for the commercial segment or to hasten cost declines to make small commercial and residential systems more attractive. Additional accelerated deployment depends on faster economic recovery, higher electricity demand and increased corporate and utility PPAs outside of the auction scheme.
Annual solar PV additions are expected to slow in 2020 after a record-breaking 2019 caused by a commissioning deadline for projects awarded in 2017 auctions. Still, utility-scale additions in 2020 are expected to demonstrate the second-highest growth, and further increases are forecast for 2021‑22.
Expansion is mainly in unsubsidised projects supported by corporate PPAs, bilateral contracts with utilities, or by combining either with a merchant tail. Strong resource potential, falling investment costs and high wholesale electricity prices have created over 7 GW under construction, with commissioning affected only minimally by delays induced by Covid‑19.
Improved regulatory conditions to shorten lead times also support the forecast. In Q2 2020, a series of legislation was passed establishing project deadlines to maintain permitting eligibility. These regulations are intended to speed up licensing approvals and minimise the reselling of permits for windfall profits.
Average annual growth is forecast to decelerate during 2023‑25 due to uncertainty over future power demand, potentially challenging the financing for new unsubsidised projects. More than half of the growth in this period will result from the resumption of competitive auctions after a three-year break to meet newly raised 2030 targets and facilitate Covid‑19 economic recovery. The new auction regime was approved in October 2020, but the tender design and timeline have yet to be announced at the time of writing. The main case assumes that 2 GW will be awarded auctioned every year, but higher volumes and strong corporate PPA demand could result in 23% higher average annual growth for utility systems in the accelerated case between 2023 and 2025.
Distributed PV growth is forecast to decline in 2020, based on the expectation that lockdown measures will have slowed installation rates relative to 2019. However, pre-pandemic regulatory reforms offering remuneration for grid exports and reducing the fixed part of retail tariffs have improved the economics of self-consumption. These reforms are expected to remain the main driver for distributed PV growth through 2025, although a potentially weaker economic climate remains a key uncertainty. Growth could more than triple if the Covid‑19 crisis has a minimal impact on business demand for self-consumption and if economic recovery is strong.
The Netherlands is forecast to add over 2.7 GW of solar PV across all sectors in 2020, 13% more than 2019. Driven by SDE+ auction rounds and net metering, there were over 500 MW of additions in first half of 2020. While the installation rate slowed during the first wave of the Covid‑19 pandemic, capacity additions accelerated from May through July.
PV additions are expected to be in line with the 2020 level in 2021 and 2022 owing to commercial applications. In 2019, the government introduced the requirement to verify network availability before competing in an SDE+ auction, which challenged expansion in some areas. High electricity prices and a generous net-metering scheme support residential expansion.
Beyond 2022, policy deadlines drive PV capacity additions: the strongest growth is forecast for 2023, as remaining SDE+ and new SDE++ projects commission before subsidies are phased out; increased technology competition in the SDE++ support scheme is a forecast uncertainty, leading to declining additions in 2024 and 2025. In addition, net metering credit rates will be reduced 9% annually starting in 2024, reducing the profitability of residential PV projects. At the same time, declining equipment costs could raise demand for commercial and residential solar PV, resulting in higher growth in the accelerated case.
France’s PV capacity additions are expected to amount to 1.3 GW in 2020, the highest level since 2012. This 50% growth compared with 2019 results from the commissioning of projects from auctions held during 2017-18 for large buildings and ground-mounted installations.
Annual additions accelerate in 2021 and 2022 owing to almost 7 GW of capacity awarded in previous auctions, with utility-scale projects accounting for almost two-thirds of the expansion. Residential systems under the FiT scheme are also expected to make a small additional contribution to the forecast.
In April 2020, the government published its new multiannual energy plan (the PPE), which confirms its commitment to 20 GW of PV capacity by 2023, as well as annual auctions for 2 GW of ground-mounted projects and 0.9 GW of large rooftop installations up to 2024.
Recent policy developments, such as PV installation obligations for new warehouses, supermarkets and parking canopies, extension of FiT eligibility to larger rooftop projects, tax cuts for large PV installations, and general tax reductions for enterprises as part of recovery measures, are also expected to accelerate deployment, especially for the commercial segment. However, the capacity of commercial PV developers to scale up deployment in the short term remains uncertain: the current rooftop auction scheme suffered undersubscription in 2018 and 2019, leading to a downward revision of auctioned capacity in 2020. Assuming sustained auction subscriptions and project completion rates for future rounds, capacity additions during 2023-25 are expected to remain over 2.5 GW/year, allowing France to meet its 2023 target.
With more streamlined permitting, higher participation in auctions for rooftop installations, a higher completion rate for awarded projects and stronger uptake of PV in the residential sector, annual capacity could average near 3.6 GW over 2023-25. The allocation and modality of support from the European stimulus package could be instrumental in this regard.
Italy is forecast to add 0.8 GW of PV capacity in 2020, similar to 2019. Despite the Covid‑19 crisis, PV capacity additions in the first half of 2020 were higher than in the same period last year.
Distributed PV applications are expected to lead Italy’s PV growth in 2021 and 2022, encouraged by tax incentives, a real-time self-consumption scheme (“Scambio sul posto”) for installations up to 0.5 MW and a FIP for systems over 0.5 MW. In addition, a new 110% tax rebate for residential PV systems installed together with building energy efficiency modernisations was introduced in May 2020 as part of the Covid‑19 economic relief package, which is expected to further support PV deployment.
Beyond 2022, Italy’s PV additions are expected to expand substantially. In its National Energy and Climate Plan, Italy set a target of 52 GW of PV capacity by 2030 – almost 2.5 times the 20.9 GW installed by 2019. The auction scheme introduced in 2019 is expected to propel PV expansion towards this target.
However, only 25 MW out of 1 000 MW was awarded to PV developers. This lack of interest results partly from rules prohibiting the use of agricultural land, which has prompted many investors to seek PPA contracts and developer merchant projects. Given the uncertainty over future electricity demand and prices, the forecast expects that PV developers will win more capacity in upcoming auctions.
Streamlining the permitting process, resolving land use challenges and implementing additional policies to stimulate deployment of distributed PV could boost average annual capacity additions to 4.6 GW during 2023-25 in the accelerated case.
Poland’s PV capacity growth is expected to reach a record 1.4 GW in 2020, 44% higher than in 2019. A generous net-metering scheme and declining investment costs have created an investment boom in distributed PV, especially in the residential sector.
Furthermore, a new subsidy scheme was introduced in August 2019 enabling residential PV investors to receive government grants, with the programme budget allowing deployment of up to 1 GW of capacity. Since March 2020, another government programme supporting thermal renovation of houses has also provided preferential loans for the installation of PV systems.
Deployment in the distributed PV sector is expected to slow in 2021 due to phase-out of the subsidy programme in the second half of 2020. Meanwhile, the number of utility-scale PV projects is forecast to increase, driven by the 2019 auction.
With Poland’s National Energy and Climate Plan aiming to double the country’s share of renewables in electricity generation to 32% by 2030, the government is expected to implement additional auctions and continue to support the net-metering scheme and other incentives for distributed PV. As a result, the forecast expects an acceleration in PV additions during 2023-25.
PV deployment in Belgium is forecast to decline in 2020, as policy transitions and lockdown-related shortages in module deliveries postpone and delay rooftop installations. Following the Flemish government’s announcement in June 2020 reintroducing support for residential and commercial rooftop PV starting in 2021, installation activity is anticipated to pick up again to reach over 0.5 GW.
Belgium’s PV growth trend is expected to be sustained after 2022, with around 1.5 GW coming online in the three years leading up to 2025. Growth is primarily in the residential segment, spurred by high retail electricity prices and the reinstated investment subsidies in Flanders.
In the accelerated case, average 2023-25 additions could be up to 54% higher assuming greater profitability of residential applications under existing schemes as well as continued support for solar PV in Flanders beyond 2024.
Brazilian solar PV additions in 2020 will increase by over 30% from 2019, with distributed installations expanding the most – by over 2 GW, a record – thanks to continuation of the generous net metering programme. Mineas Gerais (the largest distributed PV market), Sao Paulo and Rio Grande do Sul are responsible for half of Brazil’s distributed PV additions, owing in part to high retail tariffs (ANEEL, 2020).
In addition, over 700 MW of utility-scale additions are forecast to become operational as some plants under the central auction scheme connect prior to commissioning deadlines to take advantage of additional revenues from the unregulated market. The average spot market price in 2020 exceeds awarded contract prices in government auctions over the last three years (CCEE 2020).
PV additions are forecast to rise further in 2021 and 2022, as utility-scale projects begin to ramp up and distributed PV applications remain strong. Nearly 30% of total PV capacity was operating in the unregulated market in 2020, and the forecast expects that nearly half of the utility-scale growth in the next two years will be outside the auctions scheme considering the relatively high prices. In addition, the Brazilian government recently reduced import duties on PV equipment to zero, improving the competitiveness of solar projects.
With net metering and attractive financing options available for consumers, distributed PV additions surpass the 2‑GW barrier in 2021. The forecast assumes that consumers and SMEs will rush to complete projects in 2022, anticipating a possible change in the net metering policy.
The number of PV projects operating outside of the regulated environment continues to increase during 2023‑25, with 75% of the expected growth facilitated through a combination of bilateral contracts with state utilities and corporate PPAs. Net metering will ensure stable distributed PV growth, assuming that low interest rates persist. However, a change in the net-metering scheme and the availability of affordable financing remain forecast uncertainties, as Brazil’s economy is expected to enter a deep recession (OECD, 2020).
Under the accelerated case, increased electricity demand leads to higher auction capacity and additional PPAs, boosting utility-scale installations. Better financial conditions and higher demand, coupled with falling equipment costs, drive faster adoption of distributed PV as more consumers take advantage of net metering.
Compared with 2019, Mexico’s PV capacity growth is set to drop almost 40% in 2020. Utility-scale projects dominate with almost 1.5 GW expected to come online, mostly from clean energy certificate (CEL) auctions held during 2015-17. The contraction in growth results partly from grid connection restrictions, imposed by the regulator and the system operator in response to reliability concerns caused by demand pattern changes during the Covid‑19 crisis.
Annual auctions were paused in 2018 to review their objectives and scope. Still, Mexico has strong slate of projects under development (over 3.5 GW) from previous auctions and corporate PPAs, expected to come online during 2020-22.
The regulation restricting the connection of renewable energy projects has been challenged by developers, and courts have granted connections to some projects. In August 2020, the Supreme Court decided to suspend the regulation, so this forecast anticipates a faster connection rate than in our May update, with 2.4 GW of utility-scale PV projects being commissioned in 2021 and 2022.
Despite the cancellation of CEL auctions, the government’s 2024 target of 35% of electricity from clean energy sources remains in place and retailers and large consumers are still required to procure certificates to meet their obligations. As large consumers account for over 40% of electricity sales in Mexico, private renewable energy auctions and corporate PPAs are expected to drive annual additions of utility-scale PV during 2023‑25.
The share of distributed applications in overall PV growth is forecast to increase owing to net metering and net billing policies, while higher unsubsidised residential and commercial retail electricity prices improve their economic attractiveness.
Nonetheless, the current political environment and the possibility of further regulatory changes create uncertainty for developers, reducing expectations for average annual additions to below the levels of preceding years. In the accelerated case, 3 GW more solar capacity could be online by 2025, contingent upon more regulatory certainty for developers and rapid economic recovery for the distributed segment.
Chile’s solar capacity additions are forecast to reach more than 750 MW in 2020, almost double last year’s amount. Capacity expansion is prompted mostly by early completion of some projects from the last auction held in 2017, with a commissioning deadline in 2024.
Additions are expected to slow in 2021 and 2022 as a result of the gap in auctions while corporate PPA activity gains traction and merchant plants suffer from declining spot prices.
Chile’s PV growth is expected to accelerate after 2022. As part of Covid‑19 economic recovery efforts, the government has fast-tracked the environmental approvals of 55 solar projects. However, the electricity auction for regulated distributors was postponed from this year to the first half of 2021 and the government reduced the auction capacity due to uncertainty over future electricity demand.
In addition, land auctions awarding 2.6 GW of wind and solar PV capacity in Q3 of 2020 indicate further solar PV deployment in Chile. Furthermore, Chile’s recently launched Casa Solar programme supports the development of distributed PV projects by allowing community groups to obtain solar panels at lower prices and receive state co-financing. This recent development helps propel distributed capacity expansion.
Thanks to constant annual additions, Chile is well on track to meet its 2025 target of 20% electricity from non-conventional renewable sources. The even greater expansion demonstrated in the accelerated case depends on higher auction capacity and increasing solar development under corporate PPAs.
Argentina’s utility-scale PV capacity is forecast to double to over 800 MW of installed capacity this year thanks to the commissioning of previously auctioned projects. Despite this expected growth, however, many projects have suffered delays related to Covid‑19, postponing pre-commissioning tests or halting construction. Delayed projects are expected to come online in 2021 and 2022.
PV expansion is expected to contract during 2023-25, as Argentina awarded only 100 MW of PV in the 2019 auction and timing of the auction round that was expected for this year remains uncertain. Outside of auctions, renewable energy projects can sign bilateral agreements with large consumers that need to comply with the country’s goal of renewable energy covering 20% of electricity demand by 2025.
However, economic slowdown due to the Covid‑19 crisis is expected to further exacerbate already existing macroeconomic challenges, affecting not only solar PV projects but also the grid expansion needed to connect renewables. The accelerated case demonstrates that Argentina’s renewable growth beyond 2022 could be much higher if projects obtain affordable financing sooner and the number of corporate PPAs climbs quickly.
Colombia’s utility-scale solar PV capacity additions are expected to increase more over the 2020-22 period than they did in 2019. Two auctions (for energy and reliability) combined will bring online almost 500 MW of utility-scale PV. The reliability charge auction is held for the purpose of ensuring the reliability of power generation capacity even during times of drought. Additionally, Colombia is expected to hold its first private renewable auction where 140 MW (20 GWh per month) of non-conventional renewable energy sources will be tendered this year.
For 2023 and beyond, the forecast assumes 1.2 GW of additional PV capacity, spurred by continuation of the auction scheme. Considering its contracted projects and government plans, Colombia could reach its 2030 target of 4 GW of non-conventional renewable energy sources five year earlier.
The Middle East and North Africa (MENA) region is forecast to add 1.5 GW of solar PV in 2020. This growth is half of the region’s expansion last year, but it is important to note that 2019 was a record year thanks to the commissioning of major projects under some of the first renewable support schemes for solar PV in the region.
For instance, the United Arab Emirates added 1.5 GW from two utility-scale projects awarded in some of the country’s first competitive auctions held in 2016 and 2017. Egypt commissioned almost 1 GW of projects under its FiT programme and Saudi Arabia inaugurated 300 MW with the country’s largest utility-scale PV plant, awarded in the first competitive solar IPP auction in 2017.
Policy transitions and irregular procurement processes are expected to result in lower additions in 2020 due to gaps in the utility-scale project pipeline. A sharp decrease is forecast for Egypt, where a switch from FiTs to competitive auctions has been slow. FiT expiration, stop-and-go tender schedules, and caps on the size of projects eligible for corporate PPAs using the net-metering scheme have driven developers to approach the state utility independently, outside of a policy scheme, to negotiate bilateral PPAs.
In the United Arab Emirates and Saudi Arabia, additions are also lower this year because new projects from both countries’ competitive auction schemes are still under construction.
Annual growth is expected to rebound in 2021, almost doubling owing to the commissioning of major IPP projects awarded in competitive auctions in the United Arab Emirates, Qatar and Oman. Annual growth increases further by 2022, reaching 4 GW per year, and averages just slightly higher during 2023-25 as capacity from other markets (Saudi Arabia, Jordan and Tunisia) begins to expand more quickly.
More than 20 GW of solar PV is expected to be added during 2020‑25, led by the United Arab Emirates and followed by Saudi Arabia, Egypt, Qatar and Oman. Net fossil fuel exporter countries are expected to account for almost half of the region’s PV expansion, compared with just one-third in the previous five-year period. Growth results mainly from the increasing economic attractiveness of utility-scale solar PV, as deployment is spreading rapidly to countries where PV previously had to compete with electricity generation from domestically produced low-cost hydrocarbons.
The main policy driver for this trend is the use of competitive auctions, which account for over three-quarters of the region’s growth and have produced record-breaking tariffs awarded to solar PV. In the past year, bids at the lower end of the spectrum ranged from USD 13.5/MWh to USD 16.9/MWh thanks to good resource potential, economies of scale, and access to low-cost financing and land. These prices are very market-specific, however, reflecting favourable financing conditions and land affordability that may not be replicable in other markets.
MENA region selected utility-scale solar PV tender prices in 2019 and 2020
United Arab Emirates (Dubai)
United Arab Emirates (Abu Dhabi)
Two key uncertainties cloud the forecast for the MENA region: first, the pace at which contractual agreements under the various policy procurement processes occur. For competitive auctions, PV expansion depends largely upon how quickly governments announce and move through the various processes, which is often unpredictable because many governments do not publish auction timelines in advance. In some countries, project development through this procurement method tends to be slower than when IPPs directly approach large consumers or utilities to formulate corporate PPAs or unsolicited bilateral contracts – which are the second-largest source of capacity growth in Egypt, Morocco and Jordan.
Second, the possible impact of the Covid‑19 crisis on near-term project development is uncertain. In Tunisia, projects have been delayed by supply disruptions and postponed grid connections (MEES, 2020), while Abu Dhabi delayed announcing the winner of a 1.2‑GW auction to adhere to social distancing measures.
In some hydrocarbon-exporting countries, minimising the pandemic’s impact of low oil prices on state budgets has temporarily diverted attention away from renewable energy plans. Almost 2 GW of solar capacity is waiting to sign PPAs with Saudi Arabia’s state utility, and Kuwait cancelled the 1.5‑GW Al-Dabdaba tender when low oil prices induced a priority shift.
These developments are expected to be temporary, however, only shifting capacity forward and not affecting long-term growth. Tendering processes have resumed in the United Arab Emirates and were extended in Saudi Arabia while large projects in Qatar (800 MW) and Oman (500 MW) reached financial close during the height of the crisis.
Average annual growth could be two-thirds higher during 2023-25 if governments accelerate auction procedures and higher power demand increases the uptake of corporate PPAs in markets that permit them. The completion of planned grid upgrades in Tunisia and Jordan, which are essential for renewable energy expansion, would also accelerate growth in the region.
While most growth in the five-year period will be in utility-scale capacity (90%), distributed PV is expected to expand 2.5 GW during 2020-25. The commercial segment accounts for 77% of the increase, owing to FiTs in Israel and net-metering in the United Arab Emirates, Egypt and Jordan.
However, recent modifications to net-metering regulations in these markets threaten the forecast. Jordan suspended network access to projects of more than 1 MW under the net-metering scheme in early 2019 due to limited grid capacity, while both Dubai and Egypt placed limits on the amount of capacity eligible for remuneration.
PV capacity additions in sub-Saharan Africa are forecast to more than double in 2020 from 2019 thanks to growth in South Africa. Even as lockdowns and border restrictions increased labour and cross-border-trade challenges in the region, the forecast shows stable annual additions, mostly from utility-scale applications awarded in previous auctions, and through PPAs and projects funded by international development groups. Policy uncertainty, off-taker risks and land rights issues are all barriers to increased additions and can stall development of not only an individual project but a large project pipeline.
South Africa will add over 400 MW of utility-scale PV in 2020 from previous tenders, the largest capacity addition since 2017. After stalled growth due to a three-year delay in PPA signing, three projects were commissioned in February and March. Although South Africa’s Covid‑19 lockdown caused construction of all renewable energy projects to stop completely in April before resuming again in late May (Pinsent Masons, 2020), another 190 MW is expected to be commissioned by the end of 2020.
PV projects from the 2015 tender, for which construction was delayed by the Covid‑19 crisis, will not face any penalties for commissioning delays and are expected to come online during 2021-22 (ReNews, 2020). In addition, small PV capacity may be awarded in the emergency government auction announced in August 2020, but given the stringent operating requirements, the capacity is not expected to be significant.
Outside of auctions, corporate PPAs represent a growing market, improving reliability for customers facing power cuts, reducing bills through self-consumption and helping corporations meet their carbon reduction goals. Two recently announced tenders are expected to increase commercial solar PV capacity by at least 80 MW during 2021 and 2022.
From 2023 to 2025, PV growth will be driven by new tenders with a total potential capacity of 8.8 GW. The first 2‑GW technology-neutral tender was launched in August 2020, while additional tenders for 6.8 GW of renewables have only been announced. Ongoing financial difficulties and grid constraints remain critical challenges to further utility-scale development. Projects awarded in previous tenders experienced lengthy delays from the award date to PPA signature, while operational projects face curtailment concerns.
Planned commercial solar PV tenders should also contribute to future growth, with over 250 MW becoming operational over 2023-25 as companies continue to expand solar PV use to improve reliability, reduce costs and shrink their carbon footprint.
As South Africa endeavours to diversify its energy supply, the accelerated case forecasts additional capacity from the Integrated Resource Plan (IRP) and capacity from municipalities contracting directly with IPPs, a measure announced this year. Commercial PV capacity also increases as more organisations put out tenders for solar PV.
Elsewhere in Africa, Covid‑19 challenges and an already-small pipeline indicate minor gains across the region this year. However, additions in 2021 and 2022 are poised to increase owing to a combination of FiTs, tenders and development agency-backed projects.
Selected Africa utility-scale solar PV additions by country and policy, 2021-22
Main policy driver
Utility-scale solar PV project development in Ethiopia, Kenya, Nigeria and Tanzania requires bilateral agreements with the governments and state-owned utilities through tenders, FiTs or PPAs. However, off-taker risks and administrative challenges have delayed financial close for many projects since 2016.
In Ethiopia, land rights issues deter development, and some PV projects have been delayed by up to one year. The latest tenders in 2019 sought to alleviate this risk, with the government providing the land for installations as part of the tender (IJ Global, 2019). Even with the improved tender process, however, current projects are forecast to connect slowly, with just over 170 MW of utility-scale PV added from 2021 to 2022 and only 360 MW added during 2023-25. Further growth is dependent upon timely project implementation and additional tenders.
Land rights issues also pose a challenge in Kenya. Even after the signature of PPAs under the FiT scheme, local governments need to approve project development, which increases project risk. Despite developers having announced a large number of projects in Kenya, the long timelines from actual tendering to commissioning means that the country is forecast to only add 120 MW of utility-scale PV from 2021 to 2022 and 280 MW from 2023 to 2025. While the Energy Act of 2019 reaffirmed the FiT policy, uncertainty over its implementation persists.
In Nigeria, PPA renegotiations have hindered previously awarded PV projects, raising project risks significantly (PV Magazine, 2019). In addition, financing challenges in Nigeria’s electricity sector hamper the necessary grid expansion required to connect large-scale renewable projects.
Given its solar PV potential, sub-Saharan Africa’s renewable capacity expansion could be twice as high, as demonstrated in the accelerated case. This would, however, require countries to implement policies addressing off-taker and land acquisition risks. Timely implementation of announced auctions and faster grid expansion are also needed.
Half of the people living in sub-Saharan Africa do not have access to electricity, so off-grid solar PV is expected to improve electricity access throughout the region. The forecast expects over 1 GW of new off-grid PV capacity to come online in the next five years, representing 20% of all PV additions in the region.
Capacity expansion is in the form of mini-grids and solar home systems. Prior to the pandemic, government funding and development agency grants financed numerous state-sponsored RFPs for mini-grid solutions to bring power to under-served populations and create critical infrastructure. In addition, decreasing PV system costs have enabled individual consumers to acquire solar home systems to power their homes.
The Covid‑19 crisis has served to heightened interest in developing mini-grids, as relief packages have emphasised investing in renewable energy systems and programmes to power health and sanitation infrastructure and to support off-grid electrification for under-served populations.