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.

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.

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. 

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%.

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. 

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.

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. 

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.

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.

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.

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.