Annual net wind capacity additions are expected to reach 65 GW in 2020, 8% more than in 2019. Covid‑19 measures led to onshore construction activity slowing down from February to April due to supply chain disruptions and logistical challenges in many countries, but the offshore wind sector has been only mildly affected by delays caused by the Covid‑19 crisis due to long project lead times. For 2021, the forecast assumes a further acceleration of wind additions to 68 GW (7.3 GW offshore), driven by delayed onshore projects becoming operational as key countries in Europe and the United States have passed regulations providing flexibility for commissioning deadlines.

In 2022, global annual installations return to the 2019 level due to the phase-out of incentives in major markets in the People’s Republic of China (“China”) and United States, which is partly offset by faster expansion in Europe. The share of offshore capacity in total wind additions reaches almost 15% in 2022 – 50% higher than in 2019 – thanks to acceleration in key European markets and large capacity becoming operational in nascent markets such as France, Korea and Viet Nam while the Chinese market slows. The United States is expected to join the ranks of the largest offshore markets after 2022.

Annual global wind additions in 2023-25 could range from 65 GW in the main case and 100 GW in the accelerated case. Accelerating deployment will require the enhancement of policy support schemes, more investment in grids, eradication of social acceptance and permitting challenges, faster expansion of corporate PPAs and alleviation of regulatory uncertainties and off-taker risks in emerging markets. The share of offshore wind in total wind additions is expected to have increased further by 2025, reaching 20% as deployment in new markets gains momentum.

Onshore wind capacity additions are expected to reach 60 GW in 2020, 11% more than in 2019. Onshore wind developers and equipment manufacturers adopted to the “new normal” under Covid‑19 measures and accelerated construction activity in May after a slowdown in the first quarter of this year. As a result, the forecast has been revised upwards 26% from the May update.

China is most responsible for the revision, accounting for almost half of global onshore wind capacity growth this year (the highest since 2015) because developers are rushing to complete projects before the phase-out of subsidies. Additions in the United States also jump by over 30% this year, almost making up for the slowdown in Europe, whose contribution to global growth is at an historic low.

Onshore wind capacity additions are expected to further accelerate in 2021 thanks to the commissioning of delayed projects in Europe (mostly in France, Germany, Sweden and the Netherlands), and to faster growth in India and Latin America. For 2022 additions, the forecast assumes a slowdown in global deployment, mainly due to lower additions in China and the United States caused by planned changes in support policies, which will be only partly offset by growing expansion in Europe. Delayed auctions in Brazil, Chile and Argentina this year – due to lower-than-expected demand and macroeconomic uncertainties – also negatively impact 2022 additions. 

Offshore wind capacity additions are forecast to reach 5.3 GW in 2020, 13% less than 2019 growth. The forecast remains unchanged from the May update, as the offshore wind industry has been largely shielded from the Covid‑19 crisis. For the first time, China accounts for over half of global offshore wind expansion, while European countries provide the remainder.

Additions are expected to reach a record 7.3 GW in 2021, led by China as developers meet the FiT commissioning deadline, while the first large-scale commercial offshore wind project becomes operational in Chinese Taipei. In 2022, despite slowdown in China, offshore capacity is expected to increase further thanks to higher deployment in the United Kingdom and France, and in other markets in Asia. With an extensive slate of projects supported by auctions, the United States is anticipated to become one of the largest offshore markets in 2024.

Support policies and continuous cost reductions are expected to be the main drivers of wind deployment in the next five years. Globally, 40% of all wind capacity forecast to come online during 2020-25 is supported by administratively set tariffs (FiTs or a floating FIP), followed by 35% supported by auctions scheme. Competitive auctions dominate growth in all regions except China and the United States.

In the United States, the main stimulants are corporate PPAs, tax credits and renewable portfolio standards (RPSs), and other revenue sources (wholesale prices, green certificates, etc.). In China, administratively set tariffs are expected to support almost all wind additions until 2025, and after 2020, tariffs for new onshore wind are set at provincial power benchmark prices. Globally, the transition from administratively set to competitively set remuneration policies is expected to accelerate in the next five years as costs continue to decline and the wind industry expands. 

The cost of electricity generated from onshore wind continues to decrease, with the global average falling to USD 53/MWh in 2019. Thanks to advancements in turbine design, capacity factors are rising, making projects bankable even in areas with low wind speeds. The average LCOE for new onshore wind is expected to decline 15% during 2020-25 – a slower pace than in previous years – because larger shares of investment are going to more expensive markets in Europe instead of China. In addition, wind farms are increasingly been built at lower-wind-speed sites.

Over 2023-25, average annual wind additions could range from 65 GW in the main case to 90 GW in the accelerated case. Although they are becoming more cost-competitive, wind projects increasingly face permitting and social acceptance challenges in addition to policy uncertainties. Faster wind capacity growth in the accelerated case would be possible with:

• Higher targets and a robust policy framework under China’s new 14th Five-Year Plan and the continuation of provincial auctions.
• Rapid expansion of competitive auctions and elimination of social acceptance and permitting challenges in Europe.
• Extension of tax incentives, faster expansion of corporate PPAs, and timely implementation of RPSs and of offshore wind auctions and procurements in the United States.
• Resolution of grid connection, land acquisition and DISCOMs financial health problems in India.
• Additional auction capacity and bilateral contracts in Latin America thanks to faster demand recovery.
• Policies to address regulatory uncertainties, off-taker risks and grid connection challenges in the ASEAN region and Africa.
• Faster development of electrical grids to reduce bottlenecks when integrating wind capacity into power systems.

Faster net capacity growth of onshore wind also hinges on policies for repowering and refurbishment, especially in Europe and the United States. By 2025, over 180 GW of global wind capacity is expected to be at least 15 years old: 86 GW in Europe, 39 GW in the United States and 30 GW in China. Repowering old turbines with new technology usually results in higher capacity and generation from fewer turbines, while taking advantage of existing grid infrastructure and land. If supporting policies are introduced in a timely manner, repowering may provide an additional boost to onshore wind additions and mitigate the adverse effects of first-generation wind turbine retirement.

2020 will be the strongest year of onshore wind deployment in the United States since 2012 as projects qualifying for the full PTC add 12 GW, an over 30% increase from 2019. The Covid‑19 crisis caused little to no market slowdown, with a record 4.3 GW of new capacity added in the first two quarters of this year. The US Treasury’s extension of PTC Safe Harbour provisions will mitigate any lingering construction challenges and delays related to Covid‑19.

The pace of additions is expected to decrease in 2021 and 2022 due to the PTC phase-down and a possible decline in the availability of tax equity, with both factors making projects less profitable. Project sponsors’ revenues have fallen significantly with the economic slowdown, making it more difficult for them to monetise tax credits for developers (AWEA, 2020). Lower revenues and scarcity of capital have produced fewer projects in advanced development, the longest consecutive decline since 2016, and will result in a more than 40% decrease in additions from 2021 to 2023.

The PTC phaseout schedule also affects additions beyond 2022, although a small peak is forecast for 2024, driven by the final PTC commissioning deadline for projects that qualified in 2020. Beyond tax incentives, state-level incentives such as RPSs and corporate power purchase agreements are expected to encourage onshore wind growth.

State RPSs represent a growth opportunity but also present challenges. The largest markets (Texas, Iowa and Oklahoma) have met their state-mandated targets and can still export across state lines, but segmented regional grids and RPS requirements to procure power from a regional power pool necessitate faster development of nascent and new markets. States with low installed wind capacity have ample potential but could encounter barriers, including public opposition and land constraints. Smaller plant sizes and relatively low capacity factors (compared with mature wind markets) result in higher generation costs, even as the price of wind power continues to decline.

In the accelerated case, additional capacity expansion results from lower prices and greater corporate PPA and RPS demand, especially in states where wind capacity is currently limited. IEA forecasts have excluded an additional extension of the PTC, which could lead to higher deployment than in the accelerated case.

The US offshore wind market is expected to emerge during 2023‑25, with over 5 GW becoming operational as projects in New Jersey, New York, Massachusetts and Rhode Island are commissioned. The US Bureau of Ocean Energy Management is scheduled to announce its decision regarding the 800‑MW Vineyard Wind farm by the end of 2020, a last major step for the project to advance.

Along with federal permitting approvals, challenges to offshore wind projects in the United States include a lack of local policy clarity, insufficient transmission and harbour infrastructure, relatively high costs and social disapproval. Still, with a large amount of capacity already awarded, the United States is forecast to install more offshore wind capacity in 2024 than any other country in the world.

Five states are attempting to mitigate the risks by including offshore wind in their comprehensive energy plans: they organised eight offshore wind tenders totalling over 10 GW through 2020, and awarded prices are beginning to match those of European offshore wind auctions over the same period. The success of these tenders has led to the planning of tenders for an additional over 10 GW of capacity, impacting growth beyond the forecast period.

The Japanese wind market has started to expand significantly over the past few years and is set to accelerate further in 2020. The country’s generous FiT has prompted development of a large collection of onshore wind projects slated for completion by 2025. While Japan’s offshore wind market is still at an early stage of development, several FiT-supported projects will start construction in 2020 and the first offshore turbines are expected to become operational at the end of 2022. 

The growth trend is expected to continue beyond 2022 as more FiT projects reach completion, causing Japan’s total wind capacity to double by 2025. Given longer development timelines and the large FiT project pipeline, the impact of Japan’s transition to a FIP in 2022 will be limited during the forecast period.

In addition, the government is expected to award 1.5 GW through an offshore wind tender next year, supporting capacity growth beyond 2022. Additional growth in the accelerated case is highly dependent on faster construction of FiT projects and offshore tender implementation, given Japan’s limited experience in the wind industry.

Australia’s wind capacity additions are expected to increase 35% to 2 GW in 2020, driven in part by the country’s Large-scale Renewable Energy Target (LRET) that has given wind projects revenue from the large-scale generation certificate (LGC) market. However, certificate prices in the spot market fell from over AUD 80/MWh in January 2018 to AUD 50/MWh in August 2019 because the number of accredited wind and PV projects will exceed the LRET this year (AEMC, 2019).

The forecast therefore expects wind additions to decline in both 2021 and 2022 as a result of lower returns. Furthermore, potential connection delays and curtailment issues are raising project risks significantly, an element in the fact that no projects reached financial close in Q2 2020.

Beyond 2022, corporate PPAs and merchant projects are expected to promote wind expansion in the absence of a new LRET and declining certificate prices. However, lower corporate electricity demand due to the Covid‑19 crisis remains a forecast uncertainty for 2023-25. Given Australia’s ample resources, average annual wind additions could return to 1.5 GW during 2023-25 in the accelerated case, aided by planned grid upgrades and commissioning of the New South Wales Central-West Orana Renewable Energy Zone, a renewable infrastructure project forecast to deliver up to 3 GW of additional renewable capacity.

Germany’s wind capacity additions will continue to decline in 2020 due to the lull in offshore wind project development created during the policy transition from FiTs to competitive auctions. Conversely, onshore wind capacity is expected to increase slightly as projects from previously held auctions continue to be commissioned amid the lockdown measures.

Over 800 MW of onshore wind capacity were installed in the first eight months of 2020 (Bundesnetzagentur, 2020), but the impact of the lockdown on construction timelines, coupled with the six-month extension of commissioning deadlines granted by the government, could push the commissioning of late-stage projects into 2021.

The pace at which early projects will be decommissioned remains a key uncertainty in the forecast of Germany’s net wind capacity growth. By 2021, 2 GW of wind projects will have reached the end of their 20-year support payments. Whether their operations are extended depends on the business case, which may be jeopardised by a weaker economic climate. Already in the first half of 2020, 84 MW have been taken offline (Deutsche Windguard, 2020), an amount that could rise further in the second half of the year.

Growth in onshore wind capacity is expected to increase in 2021-22, and overall capacity expansion accelerates slightly during 2023‑25 as new offshore wind projects are commissioned. Competitive auctions to support new 2030 targets for both onshore wind (71 GW) and offshore wind (20 GW) are the main driver for growth. However, undersubscription in onshore auctions remains a risk due to ongoing permitting challenges. Since 2017, 10.5 GW of onshore wind have been on offer in auctions, but only 6.6 GW were awarded because administrative complexity and local opposition created long permitting wait times.

Germany’s net onshore wind growth could be 25% higher during 2023-25 if policies address permitting and decommissioning challenges. The Investment Acceleration Act proposes allowing construction to continue during any litigation processes, while a new draft of the EEG (EEG 2021) was introduced to provide financial incentives for local communities to accept new projects and to remove restrictions on new constructions in northern Germany while also creating a quota for new-builds in the south.

While the decommissioning of 12 GW of onshore wind turbines remains a risk for net growth over the forecast period, the new EEG 2021 proposes extending payments to projects reaching the end of their support scheme term. This would avoid decommissioning and instead encourage refurbishment and repowering. 

France is expected to add just under 1 GW of onshore wind capacity in 2020, one-third less than last year. Among projects coming online this year are the ones awarded in the 2018 auction and under the former FiT and FIP schemes. Annual onshore wind additions are expected to accelerate in 2021 and 2022, with 1.8 GW awarded in various auction rounds since 2018. Furthermore, the multiannual energy plan (the PPE) has scheduled tenders for 1.9 GW of onshore wind capacity per year until 2024, supporting the forecast for 2023-25.

Having been awarded in 2012 and renegotiated in 2018, France’s first large-scale (480‑MW) offshore wind project (Saint-Nazaire) closed financing this year and is expected to come online in 2022, while another 2.9 GW of auctioned projects are scheduled for commissioning during 2022-25. Although offshore wind is expected to make up one‑fifth of wind capacity additions over the entire forecast period, meeting the government’s 2.4‑GW offshore wind target by 2023 will depend on the resolution of social acceptance challenges and timely project commissioning. 

Sweden is expected to add more than 1.3 GW of new wind capacity this year, consistent with 2019 additions, mostly through corporate PPAs. However, construction delays and supply chain disruptions resulted in lower-than-expected additions in the second quarter of 2020, despite continuous construction activity since the onset of the pandemic.

The forecast anticipates nearly 3 GW of wind growth in 2021 and 2022 as previously contracted projects are completed to meet their PPA obligations. Given the numerous projects currently under construction in Sweden, the country’s delays related to Covid‑19 and its high volume of turbine orders, 2021 is forecast to be a record year for additions. Growth beyond 2021 is contingent on a follow-up programme to the green-certificate scheme and the resolution of grid congestion issues.

Italy’s wind capacity additions are expected to be 55% lower than in 2019, falling to only 0.2 GW in 2020. Wind market activity has been curtailed since 2013 due to lack of a support scheme, but the new auction scheme introduced in 2019 is expected to change this trend during the forecast period. Wind developers won 90% of the 1 GW auctioned last year, at a rate of EUR 57/MWh in the first round and EUR 64.9/MWh in the second. Most of these projects are expected to come online in 2022.

To meet the National Energy and Climate Plan’s target to achieve almost 9 GW of additional wind capacity by 2030, the government plans to auction almost 5 GW of wind and PV capacity by the end of 2021. Annual installations are therefore expected to remain at 1 GW during 2023‑25 thanks to auctions and the development of corporate PPAs, but 1.7 GW could be achieved in the accelerated case with auction expansions and the facilitation of permitting process. In addition, 5.8 GW of wind capacity will have been operating for more than 15 years by 2025, calling attention to repowering potential. 

Brazil is forecast to add over 1.3 GW of wind capacity in 2020 – over 30% more than 2019 owing to government auctions and projects developed in the unregulated market through bilateral contracts. The Covid‑19 crisis has had minimal impact on wind construction activity overall.

Despite the slight rise this year, onshore wind additions in 2019 and 2020 are significantly below historical levels due to low auction capacities in the last five years. For instance, awarded wind capacity declined from 10 GW per year during 2011-15 to 5 GW in 2016‑20.

Annual expansions of more than 1.5 GW are expected in 2021 and 2022, with over half of the growth contracted outside the government auction scheme. However, the number of free-market bilateral contracts and government auctions depends on future electricity demand, which is highly unpredictable because Brazil is expected to enter a deep recession due to Covid‑19 economic upheaval (OECD, 2020).

Considering macroeconomic uncertainties and postponement of the 2020 A-4 auction, Brazil’s annual average wind capacity growth during 2023-25 could range from 1 GW in the main case to 1.5 GW in the accelerated case. The accelerated case assumes higher wind capacity procured through the unregulated market and a larger amount of capacity auctioned in 2021 as electricity demand recovers.

Prompted by past auctions (in 2016 and 2017), Chile’s wind capacity additions will reach almost 600 MW in 2020 – a record level despite the Covid‑19 crisis. Furthermore, a peak in additions is expected in 2021, followed by a slowdown in 2022 as projects acquired in the last auction (of 2017) are commissioned. 

Capacity additions in Chile are expected to regain momentum after 2022, as a 2.7‑TWh technology-neutral electricity auction is expected in the first half of 2021 to meet the estimated demand of regulated clients in 2026. (According to the regulator, an additional 3.7 TWh will also be awarded to meet 2027 electricity demand.) The forecast expects that some wind projects from these auctions will be commissioned early to take advantage of high spot market prices. In addition, the government has also held an auction to allocate public land for renewable energy projects to address acquisition challenges. All together, these auctions are expected to lead to 2.3 GW of wind additions during 2023-25.

Argentina’s onshore wind capacity will expand almost 900 MW in 2020, slightly more than last year. Additions result from capacity previously auctioned under the RenovAR programme, despite Covid‑19-related delays that caused grid connection setbacks and temporarily halted construction. Wind additions are expected to lose speed in 2021 and 2022, as auction volumes fell from 1 GW in 2017 to only 128 MW in 2019.

The share of renewables in electricity demand needs to more than double to reach the government’s target of 20% by 2025. Argentina’s already-challenged macroeconomic environment was profoundly affected by the Covid‑19 crisis, so limited access to affordable financing and weak grid infrastructure threaten wind capacity growth in spite of the country’s excellent resource availability and cost-competitiveness.

The accelerated case therefore assumes that projects obtain financing sooner; transmission infrastructure improves; and the number of corporate PPAs increases quickly, allowing for almost 5 GW of total installed capacity by the end of the forecast period.

Colombia’s installed wind capacity is expected to start increasing in 2021, thanks to two auctions held in 2019. Together, the long-term renewable auction and the reliability charge auction will bring over 1.5 GW of additions online. However, the social consultation process as well as the delay of a new 500‑kV transmission line required to connect capacity in northern La Guajira may prevent some projects from being commissioned on time (i.e. by 2022).

In 2023 and beyond, Colombia’s capacity expansion is spurred by projects remaining from the 2019 auctions and from a third renewable auction expected in 2021.

South Africa will add around 380 MW of new capacity in 2020, reversing the stalled growth of the past two years. This capacity was tendered in 2015 with PPAs signed in 2018, and the outstanding capacity from the tender (600 MW) is forecast to be connected in 2021 and 2022. As the 2020 technology-neutral emergency tender requires strict operating standards and project commissioning by 2022, it implicitly excludes wind projects because of their long developmental lead times and low capacity factors.

Capacity additions lose momentum again after 2022 due to policy uncertainty. A tender for 6.8 GW of renewable capacity was announced in September 2020 with an expected auction round scheduled for Q2 2021, so an additional 500 MW is forecast for 2025, taking previous auction volumes and timelines into account. Force majeure notices for curtailment (sent by Eskom to wind power producers during the Covid‑19 lockdown) add an additional investment risk, as compensation for future curtailment has yet to be agreed upon.

Additional expansion in the accelerated case, based on the government’s targets for new wind power procurement (1.6 GW per year beginning in 2022), assumes greater policy certainty and the mitigation of network availability and curtailment risks.

Wind energy development has been slow in Kenya, Ethiopia and Tanzania due to a variety of risks, including financial exposure, land acquisition challenges and lack of critical infrastructure for power projects.

Kenya will add 100 MW of new wind capacity in 2020. The development required a new 17‑km transmission line to connect to the grid, exemplifying the type of network upgrades needed for large-scale wind projects. Additions are expected to increase during 2023 to 2025, as two projects with a combined capacity of 170 MW are to be commissioned. Both projects have been delayed by land disputes, even after their PPAs were signed (ESI Africa, 2017; Nigeria Electricity Hub, 2020). 

Ethiopia is forecast to start commissioning projects totalling over 500 MW of new capacity between 2021 and 2022. This capacity has received multiple streams of financing from international organisations, including a new round of capital in 2020 (ReveNews, 2020). Land rights issues have led to delays, as resettlement negotiations were conducted only after financial close (The Reporter Ethiopia, 2018). Although Ethiopia’s government has identified areas for additional wind development through 2025, it has not announced a policy scheme to support the plan.

The first onshore wind project in Tanzania was commissioned this year, with another 120 MW expected during 2022‑25 thanks to a grant from the Government of Finland (Windlab, 2018). A tender launched in 2018 for 200 MW is still under review and is included in the accelerated case.

As potential for wind energy development in sub-Saharan Africa is strong, the accelerated case demonstrates over 30% more additional capacity than the main case. However, creating policy frameworks to engage local communities and raising investments in transmission infrastructure will be necessary to facilitate increased development and shorten project timelines. Ensuring early access to financing would also reduce projects’ risk exposure, encouraging greater investment.