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IEA (2026), Renewables 2026, IEA, Paris https://www.iea.org/reports/renewables-2026, Licence: CC BY 4.0
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Regional forecasts and data
Following a decline in 2026, renewable capacity additions recover gradually as accelerating growth in emerging markets offsets China’s slowdown, while advanced economies remain flat
Global renewable capacity additions are forecast to decline 11% in 2026, ending 21 consecutive years of record-breaking annual expansion, but are still at the second-highest level ever registered. This contraction results mainly from a deceleration in China’s solar PV deployment, which has been the engine of global PV expansion, making up 60% of additions worldwide since 2023. Chinese solar PV additions were almost 55% lower in the first nine months of 2026 than in the same period in 2025, reflecting weakening project economics with the government shifting its support framework from fixed remuneration to competitive auctions in June 2025.
China’s wind capacity additions are expected to slow in 2026, but much less sharply than solar PV, as the commissioning of large-scale projects partly cushions the impact of recent policy reforms. Faster wind deployment in Europe and the United States offsets China’s slowdown, leaving global wind capacity additions broadly unchanged from 2025.
Global annual renewable capacity additions in 2026-2031 are expected to average almost 800 GW/yr in the main case forecast, 57% above the 2020-2025 average. Following the decline in 2026, China’s annual capacity additions recover gradually, but remain 13% below the 2025 level in 2031. In July 2026, China released its 15th Five-Year Plan for Renewable Energy Development, setting an indicative cumulative target of at least 2 800 GW of wind and solar PV (AC) capacity by 2030. This implies around 190 GW of combined annual deployment of wind and solar PV (in alternating current [AC]) through 2030. Nevertheless, the main case expects China to exceed these policy targets by almost 30%, continuing its established trend of surpassing the ambitions of previous Five-Year Plans.
Outside of China, annual renewable capacity additions are forecast to increase 27% between 2025 and 2031, mainly in emerging markets and developing economies (EMDEs) as strong policy momentum and growing energy security concerns accelerate deployment. Led by solar PV, annual renewable capacity additions across India, the Association of Southeast Asian Nations (ASEAN), sub-Saharan Africa, Latin America, the Middle East and North Africa (MENA) and Eurasia are projected to match those of advanced economies over the forecast period for the first time.
India’s robust growth continues to benefit from a decade of proactive policy support that has partly cushioned the electricity sector from the impacts of the energy crisis. In both the ASEAN and sub-Saharan African markets, two policy responses underpin growth: first, some governments introduced more ambitious renewable energy targets following the Middle East crisis; second, others adopted measures to accelerate the implementation of previously announced targets. In addition, consumers increasingly adopt decentralised rooftop solar PV systems to mitigate the impacts of daily load shedding and grid unreliability.
In advanced economies, renewable capacity additions plateau following strong acceleration since 2021 as grid integration, financing and permitting challenges mount. In Europe, annual renewable capacity additions are forecast to average around 100 GW over 2026-2031, remaining consistent with 2025. In the United States average renewable capacity additions are slightly higher compared with the 2025 level to accommodate rapidly growing electricity demand, mainly from data centres. Meanwhile, Asia-Pacific annual capacity trends show gradual acceleration relative to 2025 – particularly in Korea and Japan – owing to a series of policy improvements and market reforms.
Solar PV continues to lead global capacity expansion through 2031 while China’s historical dominance is expected to weaken
Renewable power capacity is projected to expand over 4 770 GW between 2026 and 2031, making up over 80% of total global power capacity additions. This expansion over the forecast period marks a 57% acceleration compared with 2020-2025.
Solar PV remains the key growth driver, accounting for three-quarters of global renewable capacity expansion to 2031. Utility-scale solar PV capacity is forecast to expand 2 075 GW during 2026-2031, while distributed applications – residential, commercial, industrial and off-grid systems – are set to grow an additional 1 530 GW.
Low generation costs relative to other renewable and conventional technologies, combined with robust policy support, make solar PV economically attractive for developers, businesses and consumers alike. Furthermore, faster permitting and broader social acceptance have made solar PV the preferred technology for many utility-scale developers, even for situations in which alternatives such as onshore wind cost less. Distributed solar PV is also expanding rapidly as consumers across an increasing number of locations deploy self-consumption systems to reduce electricity bills and/or enhance electricity service reliability.
China’s declining share of global renewable capacity growth is shifting market focus to India, the second-largest contributor to global expansion. China accounted for over 60% of global renewable capacity expansion in 2025; however, its share is projected to moderate to 53% over the forecast period. By contrast, India’s renewable capacity expansion between 2026 and 2031 is expected to be 2.6 times greater than in the previous six-year period, almost doubling its contribution to global growth to nearly 8.5%.
ASEAN, MENA and sub-Saharan Africa are collectively tripling their pace of renewable capacity growth over the next six years, primarily installing solar PV systems. Driven by the rapid implementation of ambitious targets across many ASEAN countries following the recent energy crisis, the ASEAN region is projected to have the highest annual solar PV additions by 2031, surpassing Latin America, MENA and sub-Saharan Africa over the forecast period.
Annual renewable capacity additions in Latin America remain above historical levels despite declining from their 2026 peak, driven by slower growth in Brazil while Mexico, Chile and Colombia remain broadly stable. Meanwhile, in the MENA region, Saudi Arabia is set to accelerate its renewable expansion fivefold between 2026 and 2031, followed by the United Arab Emirates, marking a structural step-change in the region’s energy market. In sub-Saharan Africa, growth remains led by South Africa and Nigeria, which account for almost half of the region’s new capacity.
The global renewable capacity forecast remains broadly unchanged from last year, but this conceals significant regional shifts that offset each other
Globally, renewable electricity growth remains broadly in line with last year’s forecast. The small upward revision of 2%, or just 75 GW, reflects recent policy, regulatory and market developments since October 2025. China’s forecast is reduced by the largest margin, nearly 116 GW. However, more positive outlooks in ASEAN, India, the United States, sub-Saharan Africa and Latin America offset the slowdown in China. The largest upward revision in percentage terms is for sub-Saharan Africa, where solar PV increasingly provides an alternative for millions of consumers to secure electricity service during rolling blackouts.
Note: The comparison of Renewables 2025 and Renewables 2026 forecasts covers renewable capacity growth from 2026 to 2030 (instead of 2031) because the Renewables 2025 forecast period ended in 2030.
China: The downward revision stems from solar PV additions falling more than 50% year-on-year during January-September as the shift from fixed tariffs to competitive auctions eroded the profitability of utility-scale and distributed projects. Onshore wind, by contrast, held broadly at last year's record level and has been revised upwards, supported by policies favouring large-scale megabase projects and by capture prices almost 40% above solar PV’s.
Upward revisions to hydropower and CSP reflect measures to ease system integration, including accelerated pumped-storage approvals and more ambitious CSP targets announced in December 2025. Offshore wind has been revised downwards due to cost increases following the shift to competitive auctions and limited provincial-level support, while bioenergy uptake has slowed since 2024 amid weaker waste-to-energy growth.
European Union: Like last year, we are revising our forecast for distributed solar PV and offshore wind downwards, while utility-scale solar PV goes up to reflect higher auction volumes or award rates in Germany, Italy, Poland and France. The distributed solar PV outlook is revised downwards for all major EU markets due to a roll-back in support (i.e. the discontinuation of net metering in the Netherlands; EEG2027 feed-in tariff and net-billing cuts in Germany; lower subsidies and gross metering in Poland; and the phaseout of renovation rebates in Italy).
For offshore wind, forecasts have been revised down in Europe primarily because of failed or repeatedly delayed tenders in Germany, Denmark, Belgium and the Netherlands. For instance, Germany's August 2025 round drew zero bids; the Netherlands' 2025 Nederwiek I-A tender received no applications; and Belgium's CfD auction was deferred from Q4 2024 towards end-2026. However, several countries are revising their offshore wind auction designs to attract bidders. For instance, following Denmark’s failed 3-GW tender in December 2024, the government redesigned the auction and awarded 1.8 GW across two sites, with bids of EUR 67.42/MWh and EUR 72.50/MWh. As both projects are expected to be commissioned beyond the forecast period, they are not included in this forecast.
United States: The solar PV forecast has been revised 45% upwards because the pipeline is larger than expected for financed utility-scale projects qualifying for tax credits before the phaseout in 2027. Rapidly rising electricity demand from data centres further strengthens the outlook, as solar PV technologies can bring new generation online very quickly while supply-chain constraints continue to delay gas turbine availability. The federal court decision restoring the 5% cost-based safe harbour as an alternative to the physical work test provides a smaller additional boost, reopening a faster route for some wind and large solar projects to qualify for the 30% investment tax credit (ITC)/production tax credit (PTC) ahead of the 4 July deadline.
India: While the renewable capacity outlook has been revised upwards from last year, trends vary across technologies. Solar PV underpins stronger growth, supported by rapid recent deployment, a large pipeline of awarded projects and expanding uptake of rooftop systems backed by policy support. Pumped-storage hydropower is also gaining momentum thanks to more efficient administrative processes and an expanding project pipeline. In contrast, onshore wind is losing ground amid weaker deployment, limited auction volumes and increasing competition from solar PV paired with storage.
ASEAN: Across the upward-revised ASEAN markets, distributed solar PV leads growth, followed by utility-scale, owing to improved market access (through direct and virtual PPAs, and clearer PPA frameworks); new or expanded support schemes (net-billing FiTs, and higher net-metering caps and rooftop quotas); and strong auction results and subscriptions. Robust commercial and industrial projects and data-centre demand reinforce the trend. In addition, the forecast for off-grid solar PV has been revised upwards because consumers are increasingly installing rooftop solar systems outside of policy schemes to improve their electricity service.
Sub-Saharan Africa: A 42-GW rise in distributed PV uptake over the forecast period, including rooftop and off-grid systems, has boosted the total solar forecast upwards by nearly 36 GW, while utility-scale was downgraded by nearly 7 GW due to a lack of financing and grid infrastructure challenges. Based on recent trade data, the largest forecast revision is for off-grid solar PV systems.
Middle East and North Africa: The forecast remains broadly unchanged, as stronger corporate demand, project expansions and higher targets offset slower renewable hydrogen development and project delays linked to the Strait of Hormuz closure.
Europe’s renewable energy expansion remains strong but plateaus as grids, permitting and weaker distributed PV slow momentum
Europe is forecast to add over 615 GW of renewable electricity capacity over 2026-2031, almost 40% more than during 2020-2025. However, annual additions are expected to remain broadly stable at around 100-105 GW throughout the forecast period. This reflects a shift from the crisis-driven surge in distributed solar PV towards utility-scale solar PV and wind, for which deployment is increasingly constrained by grid-capacity, permitting and system-integration challenges.
Solar PV continues to be the main source of expansion over 2026-2031, with utility-scale and distributed systems together making up roughly 70% of Europe’s capacity additions, followed by onshore and offshore wind. Germany remains the largest market, registering almost 30% of regional growth, while the United Kingdom, Italy, Türkiye, Spain, France, Poland and the Netherlands together account for nearly half.
We have revised the forecast down 6% from last year, primarily because of 14% weaker distributed solar PV deployment. Following the exceptional expansion triggered by the energy crisis after Russia’s invasion of Ukraine, distributed PV markets are becoming saturated as policy support declines and retail electricity prices fall from crisis peaks. Higher electricity prices associated with the current conflict in the Middle East have not yet translated into major policy revisions or a measurable acceleration in installations.
This decline is partly offset by stronger utility-scale PV deployment arising from successful auctions in Italy, Germany, Poland and France, and by faster merchant and corporate-PPA-backed investments in Bulgaria, Greece and Spain.
Our wind deployment forecast has also been revised down 15% due to permitting and project-development delays that continue to slow the commissioning of onshore wind farms in most markets. These effects are only partly offset by larger corporate PPA volumes in Portugal, merchant projects in Hungary and simplified grid connection rules in Türkiye. Offshore wind expectations have been revised down across several markets, including, the Netherlands, Germany, Ireland, Belgium and Lithuania, reflecting delayed project awarding and slower project and grid infrastructure development. Pumped-storage hydropower has the largest relative downward revision because projects in Spain, the United Kingdom, Croatia, Austria and Romania are developing more slowly than previously expected.
Auctions to award contracts for difference or fixed-price contracts remain the main driver of utility-scale solar PV and wind expansion in Europe. They are expected to catalyse over 80% of offshore wind, almost 70% of onshore wind and 60% of utility-scale solar PV deployment over 2026-2031.
Corporate PPAs are the second most important procurement mechanism for utility-scale solar PV. Spain and Germany continue to lead the European market, with activity growing across Europe, especially in Greece, Italy, Denmark, Portugal, Sweden and Poland. By contrast, merchant deployment is expected to play a more limited role, as uncertainty over wholesale electricity prices, capture rates and curtailment continues to weigh on investment decisions.
Distributed solar PV is expected to remain Europe’s largest source of installed renewable energy capacity by 2031, despite annual deployment falling from the 45-GW peak in 2023 to less than 30 GW by the end of the forecast period – below last year’s expectations. While annual additions in 2025 were in line with last year’s expectations, early 2026 developments point to weaker deployment than previously forecast, as policy changes, market saturation and lower electricity prices weakened the business case for new systems.
In Germany, additions declined with the tightening of support measures and restrictions on electricity exports during low-price periods. At the same time, France reduced remuneration for smaller systems and shifted support towards self-consumption, while changes to net-metering schemes and subsidy reductions slowed deployment in Poland, Italy and the Netherlands.
System integration remains a key challenge across European markets. Grid congestion, long connection queues, curtailment and increasingly frequent low- or negative-price periods reduce project revenues and delay project development.
Permitting remains the second broad challenge, particularly for onshore and offshore wind. While Germany has demonstrated that reforms can expand the auction-ready project pipeline, lengthy approval procedures, legal challenges and land-use constraints continue to delay projects across much of Europe.
Additionally, offshore wind expansion is challenged by complex seabed-allocation, permitting, auction and grid-connection processes. At the same time, slower-than-expected electricity demand growth is reducing capture prices and corporate PPA demand, particularly in markets such as Spain and Finland where large industrial, hydrogen and data-centre projects have yet to materialise at scale.
In the accelerated case, Europe’s renewable capacity deployment is about 30% higher than in the main case. The largest upside gains come from solar PV, for which faster deployment of storage, flexible demand, grid infrastructure and connection reforms would alleviate curtailment and improve project economics. For wind, stronger growth depends primarily on faster permitting, facilitated repowering, more predictable spatial planning, regular auction schedules and better co-ordination of project development and grid expansion.
These measures would also improve realisation rates for awarded projects and strengthen revenue certainty for corporate-PPA-backed investments. Faster renewable energy deployment will also require speedier electrification of energy use, particularly in the most advanced markets, to support additional electricity demand.
The EU renewable electricity target for 2030 is within reach, but only with faster grid, permitting and system integration progress
The European Union adds over 480 GW of additional renewable capacity over 2026-2031, accounting for almost 80% of deployment in Europe. Solar PV provides the majority of additions, while onshore wind accelerates in markets where auctions and permitting reforms have expanded the project pipeline.
Offshore wind grows towards 2031 but remains below the trajectory towards EU countries’ combined regional ambition of around 88 GW of offshore renewable capacity by 2030, due to delays in permitting, auctions and project development. Renewable capacity is expected to reach 1 255 GW by 2030 and 1 335 GW by 2031, over 55% above 2025 levels. However, renewable power generation remains below the REPowerEU target.
According to European Commission modelling, renewables reach 69% of gross final electricity consumption and 72% gross electricity generation by 2030, consistent with a 45% renewable share in gross final energy consumption. RED III subsequently set a binding EU-wide target of 42.5% by 2030, with an ambition to reach 45%. In the IEA main case, the renewables share in electricity generation reaches only 60% in 2030. There are three reasons for this gap: national ambitions remain below the level required to meet the EU-wide target; deployment delays are affecting the technologies with the highest generation potential, particularly offshore wind; and rising curtailment is reducing the generation delivered by installed wind and solar PV capacity.
In terms of installed-capacity ambitions, the European Union is expected to reach the 2030 solar PV target of 592 GW (in alternating current [AC]), but it falls short of the 510-GW wind ambition by more than 30%. As a result, total 2030 renewable capacity is around 13% below the 1 236-GW target when calculated using the European Commission’s methodology.
Notes: The solar PV target is 592 GW in the Commission Staff Working Document COM (2022) 2030 final. We assume this value is in AC since it is similar to the “almost 600 GW by 2030” solar PV target identified in the EU Solar Energy Strategy SWD (2022) 148 final. The 2030 ambition for wind refers to the Implementing REPowerEU Plan SWD. As per the REPowerEU Plan SWD (2022) 230 final, assumed to exclude pumped storage (as illustrated in the Implementing REPowerEU Plan SWD) and to include solar PV in AC (as referred to in the EU Solar Energy Strategy).
This shortfall does not result from a lack of policy support. Competitive auctions remain widespread, corporate PPAs continue to expand, RED III provides a framework for faster permitting and the European Grids Package aims to alleviate grid connection bottlenecks.
The challenge is implementation. Germany’s permitting reforms and auction volumes support stronger growth, but offshore wind deployment remains delayed. Italy’s FER X framework strengthens the utility-scale solar PV pipeline, but transmission and permitting constraints continue to affect project delivery. Spain has a large project pipeline but requires faster demand growth, storage deployment and grid expansion. In France, lower distributed-PV remuneration hampers deployment, while in Poland and Romania growing auction activity is increasingly constrained by grid connection availability.
Auctions remain the main driver of utility-scale deployment in the European Union. Under the EU Net-Zero Industry Act (NZIA) and its implementing regulation, each member state must apply the prescribed non-price sustainability and resilience criteria to at least 30% of the auction volume each year, or alternatively at least 6 GW per year. Italy became the first member state to apply the related provisions in its 2025 FER X tender, which awarded around 1.1 GW to projects meeting supply-chain resilience requirements. As industrial policy goals become increasingly integrated into auction design, balancing supply-chain objectives with competition and timely project delivery will be increasingly important.
The 72% renewable electricity generation share required to meet the REPowerEU modelling is achieved in the accelerated case, but only with stronger policy implementation and faster infrastructure deployment.
Higher and more predictable auction volumes, especially for onshore and offshore wind, would be required to provide long-term investment visibility. Auction designs across countries would also need to better reflect financing, construction and grid-delivery risks while ensuring bankable revenues for developers. At the same time, stronger corporate PPA frameworks could broaden market access and improve project economics.
Investing in system flexibility is equally important. Employing batteries, pumped-storage hydropower, demand response, interconnections and flexible electricity consumption can reduce curtailment, improve capture prices and increase the value of renewable power generation. In parallel, member states would need to speed up permitting reforms, implement renewable-acceleration areas and streamline project approvals without weakening environmental safeguards. For wind, repowering turbines and making spatial planning more predictable could further expand the project pipeline.
Addressing grid constraints remains key to achieve faster renewable energy expansion in the European Union. Connection queue reforms are expanding across member states and are helping system operators allocate grid capacity more efficiently through stricter readiness requirements and the removal of speculative projects. While these measures should improve project realisation rates, they cannot substitute for investment in transmission and distribution networks. Better co-ordination of renewable procurement, grid expansion and connection availability will therefore remain essential, particularly for offshore wind and for renewables-rich regions located far from demand centres.
The Asia-Pacific renewable energy forecast has been revised upwards as stronger Indian and ASEAN solar PV growth more than offsets the region’s lower wind and hydropower outlook
Asia Pacific, excluding China, is forecast to add more than 840 GW of renewable capacity over 2026-2031, more than doubling 2020-2025 additions and raising installed capacity to almost 1 700 GW by 2031. India accounts for nearly half of the regional expansion, followed by ASEAN at 20%, while Pakistan, Australia and Japan together contribute just over one-fifth.
Solar PV leads the expansion, representing almost 80% of capacity additions, while onshore wind contributes 12% and hydropower 7%.
Competitive auctions drive over half of utility-scale renewable capacity growth in the Asia-Pacific region, led by India’s central and state procurement programmes, Australia’s Capacity Investment Scheme, Korea’s fixed-price contract auctions and the Philippines’ Green Energy Auction Programme. Corporate PPAs contribute another 25% and are becoming an increasingly important route to market in India, Viet Nam, Korea and Japan. Unsolicited bilateral contracts represent around 13% of deployment, particularly in vertically integrated markets such as Indonesia. Utility-owned projects, feed-in tariffs and merchant investments spur the remaining growth.
Asia-Pacific renewable energy markets are increasingly diverging as deployment matures. In advanced markets, including Australia, Japan and Korea, system integration is emerging as the key challenge, with grid constraints, curtailment and insufficient flexibility increasingly limiting growth. As solar PV penetration rises, investing in networks, storage and demand-side flexibility is becoming as important as new capacity additions.
In contrast, less mature markets remain focused on translating policy ambition into deployment. Countries such as Indonesia, the Philippines, Thailand and Viet Nam have strengthened their renewable energy targets and support frameworks, but grid connection, permitting, project execution and land acquisition challenges continue to slow implementation.
Across the region, investment increasingly depends on bankable revenue streams and predictable regulation. Inadequate grid infrastructure, project bankability and policy execution remain common barriers, highlighting the growing importance of robust market design and revenue certainty.
Our 15% (87 GW) upward revision to last year’s Asia-Pacific renewable energy forecast primarily reflects stronger solar PV growth, which more than offsets lower expectations for wind and hydropower. Upward revisions are led by India, Korea, Indonesia, Australia, the Philippines, Pakistan, Malaysia, New Zealand and Thailand, while forecasts for Japan and Chinese Taipei have been revised downwards.
With the solar PV outlook raised by more than 100 GW (+24%) for 2026-2030, it makes up almost the entire upward revision to the regional forecast, led by stronger deployment in India, Korea, Indonesia and Australia. Utility-scale solar PV contributes almost half of the increase, owing primarily to India’s stronger-than-expected deployment and large pipeline of auction-awarded and open-access projects. These gains more than offset downward revisions to utility-scale solar PV in Pakistan and Japan, while Chinese Taipei's outlook has been scaled back due to permitting, land-use and social acceptance challenges.
Distributed solar PV constitutes more than half of the solar PV upward revision. Indonesia accounts for the largest increase, thanks to stronger commercial and industrial demand, greater ambition, planned expansion of rooftop solar quotas and improved PPA arrangements. In India, continued growth under the PM Surya Ghar and KUSUM programmes, improved economics and stronger-than-expected recent deployment support a higher solar PV outlook. Meanwhile, Pakistan’s upward revision reflects continued consumer-led deployment of distributed and off-grid solar PV in response to high electricity tariffs and power supply unreliability.
Onshore wind has been revised down by over 9 GW, led by India and Japan. In India, lower dedicated auction volumes and growing competition from solar PV paired with battery storage weaken deployment prospects. In Japan, persistent project realisation challenges continue to delay deployment. Upward revisions in Australia, Korea and Thailand, reflecting larger procurement volumes and policy support, only partly offset these reductions.
Offshore wind receives the largest relative downward revision among renewable technologies. This year’s forecast is over 30% lower than last year's, primarily because of project delays and cancellations in Chinese Taipei and Korea, as well as continuing supply chain, permitting and financing challenges. Progress in Viet Nam's offshore wind project pipeline, resulting from better project-level visibility and new regulations addressing earlier bottlenecks, only partly offsets these reductions.
Hydropower additions remain sizeable despite a modest downward revision. Asia Pacific continues to be the world's second-largest hydropower growth market, although delays in India and Viet Nam scale back the outlook for conventional hydropower. Higher expectations for Pakistan and Australia partly offset these reductions. Pumped-storage hydropower has been revised upwards for Australia and India, reflecting rising flexibility needs as renewable energy penetration increases.
Meanwhile, the bioenergy and geothermal forecasts have been revised upwards. Stronger bioenergy deployment in Japan and faster geothermal expansion in Indonesia, supported by policy measures and improved project economics, contribute to higher growth expectations for both technologies.
Capacity additions across the region could be 25% higher in the accelerated case, reaching more than 1 000 GW over 2026-2031. Realising this upside potential would require faster grid expansion and connection, greater deployment of storage and flexibility resources, and higher execution rates for awarded and advanced-stage projects.
In India, higher auction volumes, faster contract signing, improved DISCOM finances and accelerated transmission and storage deployment would support faster renewable capacity growth. In ASEAN, faster implementation of power development plans and support schemes, more efficient procurement, permitting and project execution, stronger grid investment and enhanced regional interconnections would unlock further growth, particularly in Indonesia, Viet Nam and the Philippines. Across advanced Asia-Pacific markets, faster grid expansion and grid connections, more storage and system flexibility, streamlined permitting and stronger revenue certainty would improve project realisation and enable quicker renewable energy deployment.
Solar PV leads renewable capacity growth as the regional technology mix shifts away from hydropower dominance
The Latin America and Caribbean region is forecast to add 165 GW of renewable electricity capacity during 2026-2031, with solar PV making up almost 80%. By the end of the decade, installed solar PV capacity is expected to surpass hydropower’s to become the largest source of installed capacity.
During the 2010s, onshore wind was the main source of renewable capacity growth in Latin America, led by Brazil. However, annual additions have plateaued and are expected to remain broadly stable through 2031 as transmission constraints, curtailment and fewer auction opportunities hamper deployment, particularly in Brazil. Chile is expected to account for a growing share of regional wind growth towards the end of the forecast period.
Solar PV has emerged as the region’s dominant growth technology, led by Brazil and supported by expanding deployment in Chile and Mexico. While utility-scale solar growth moderates in Brazil due to grid constraints and weaker procurement, strong project pipelines, corporate PPAs and new auction activity in Chile and Mexico continue to sustain regional expansion.
Distributed solar PV is forecast to become the largest source of renewable capacity additions over 2026-2031. Most growth happens in Brazil, where net metering, high retail electricity prices and declining technology costs continue to encourage investment, while Mexico’s net-metering framework sustains steady deployment.
Brazil remains the region's largest renewable energy market, with almost 90 GW of renewable additions forecast for 2026-2031. Solar PV accounts for 86% of new capacity, increasingly in the form of distributed systems. Net metering, falling solar costs and strong free-market PPA activity continue to support deployment. However, fewer auctions, transmission bottlenecks and rising curtailment are slowing utility-scale solar PV and wind growth despite ongoing efforts to expand the grid as well as storage facilities.
Mexico is forecast to more than double its renewable capacity additions compared with 2020-2025, with solar PV accounting for over 90% of growth. Utility-scale solar benefits from the reopening of large-scale procurement through the new CFE-led auction scheme, while net metering continues to support distributed PV. Key challenges include grid constraints, permitting delays and uncertainty around the balance between state control and private-sector participation.
Chile is expected to add around 20 GW of renewable capacity between 2026 and 2031, with solar PV accounting for about two-thirds of growth and wind for most of the remainder. Strong solar and wind resources and growing corporate PPA demand support deployment. However, transmission congestion, curtailment and an increasing number of zero-price hours are becoming major challenges, reducing project revenues and making grid expansion and battery storage crucial for future growth.
Compared with last year’s forecast, renewable capacity additions in Latin America and the Caribbean have been revised up by 12 GW (9%), primarily reflecting stronger distributed solar PV deployment. Nearly three-quarters of the upward revision comes from distributed PV, led by Brazil, where favourable net-metering conditions and continued cost declines outweigh the impact of new grid-use charges. Utility-scale solar PV prospects are lower than last year, mainly because of weaker expectations for Brazil and Chile, where transmission constraints, rising curtailment and lower auction activity are slowing large-scale deployment.
Onshore wind expectations remain broadly unchanged at the regional level, as stronger growth in some markets offsets weaker prospects in Brazil and Mexico. Overall, the forecast revision reinforces Latin America’s shift towards a more solar-led growth model, with distributed PV accounting for the majority of additional capacity.
Distributed solar PV uptake accelerates renewable energy growth across sub-Saharan Africa, led by South Africa and Nigeria
Sub-Saharan Africa is forecast to add over 120 GW of renewable electricity capacity over 2026-2031, almost doubling today’s installed base and marking a clear acceleration from 2020-2025. Growth is concentrated in South Africa and Nigeria, which together account for over 40% of the regional capacity expansion, followed by Kenya, Ethiopia and Angola. Solar PV dominates the forecast, representing over 80% of new capacity, while hydropower’s share of new deployment continues to decline despite remaining important in several markets.
The main structural shift in the region is the rapid expansion of distributed solar PV. Residential, commercial and off-grid systems account for nearly two-thirds of all new solar PV capacity over the forecast period, led by Nigeria, South Africa and Kenya, but increasingly supported by broader uptake across smaller markets. This growth is driven less by centralised procurement than by consumers seeking more reliable and affordable electricity amid weak grid reliability, high tariffs, rising diesel generation costs and falling solar PV and battery prices. In Nigeria, fuel subsidy removal, mini-grid regulation and the introduction of net billing improve project economics, while South Africa’s deregulation of private distributed generation continues to support commercial, industrial and residential deployment. In Kenya, however, high electricity prices and supply unreliability remain the key drivers of distributed solar PV uptake.
Utility-scale solar PV growth remains more concentrated. South Africa accounts for 48% of the region’s utility-scale PV additions, supported by the Renewable Energy Independent Power Producer Procurement Programme (REIPPPP), corporate PPAs and Eskom’s wheeling arrangements. Outside South Africa, deployment is rising in Kenya, Namibia and Senegal, supported by dedicated procurement rounds, feed-in tariffs and offtaker guarantees, while state-led projects and development finance underpin growth in Nigeria, Ghana, and Angola. However, weak grid infrastructure, transmission bottlenecks and project bankability challenges continue to limit the pace of utility-scale expansion, especially in South Africa and Nigeria.
Onshore wind growth remains modest and highly concentrated. Around 10 GW of new wind capacity is expected over the forecast period, with South Africa responsible for roughly half of additions through REIPPPP awards and corporate PPAs. Although wind projects benefit from strong resource availability in several markets, deployment is increasingly constrained by limited grid connection availability, particularly in South Africa’s Eastern and Western Cape provinces where the best wind resources are located. Outside of South Africa, wind growth remains relatively limited and dependent on support from national utilities and development finance institutions, with additions concentrated in markets such as Senegal, Ethiopia and Kenya.
While solar PV makes up most additions, hydropower remains an important source of new capacity in some markets. Around 9 GW of hydropower is forecast for 2026-2031, with Angola and Ethiopia accounting for 50% of the regional increase. Large projects, including Angola’s Caculo-Cabaça hydropower station and Ethiopia’s Koysha hydroelectric project, underpin much of this growth.
The regional forecast has been revised up 54% (33 GW) from last year, based almost entirely on distributed PV, which has been upgraded by 42 GW, reflecting faster consumer-led deployment and improved accounting of historically underestimated distributed capacity. However, the upward revision for distributed PV is partly offset by a near 7 GW downward revision to utility-scale PV, reflecting higher offtaker risks, financing constraints and limited transmission availability. Meanwhile, the hydropower forecast is revised down by 2 GW, as the Grand Ethiopian Renaissance Dam reached full commissioning in September 2025, ahead of the forecast period and earlier than previously expected, and several large projects in Ethiopia and Nigeria have been delayed beyond 2031.
Long-term planning and energy-access initiatives still support the region’s renewable energy outlook. Updated planning frameworks, including South Africa’s Integrated Resource Plan and Nigeria’s National Integrated Resource Plan, provide a basis for future deployment, while Mission 300 continues to support grid-based and off-grid electrification. A domestic solar PV manufacturing push is also emerging, led by Nigeria, which is expected to have around 500 MW/year of module assembly capacity in 2026, and is forecast to surpass 1 GW annually by 2031. However, these early-stage ventures are unlikely to materially reduce import dependence during the forecast period.
Regional challenges remain significant, keeping renewable capacity deployment in Africa well below the substantial potential. Grid capacity constraints and transmission bottlenecks are the largest barriers to utility-scale wind and solar PV deployment, particularly in South Africa and Nigeria. Government utility offtaker risk, weak revenue collection, and procurement uncertainty continue to undermine project bankability, while distributed PV is further constrained by limited local-currency financing access, foreign exchange volatility and import policy uncertainty. In several markets, the absence of clear frameworks for grid-connected battery storage also delays the next phase of variable renewable integration.
In the accelerated case, renewable capacity additions are 46% higher than in the main case, led by faster solar PV and wind deployment. The largest upside gains depend on faster transmission expansion, including implementation of South Africa’s Transmission Development Plan and the Independent Transmission Infrastructure Procurement Programme. In Nigeria, a competitive utility-scale procurement framework, clearer licensing and wheeling rules, stronger distributed-generation regulation and bankable storage frameworks would encourage faster deployment. Expanded access to local-currency financing and continued development of domestic solar manufacturing could further strengthen distributed PV growth across the region.
The MENA renewable forecast remains stable as energy security measures and corporate demand offset a weaker renewable hydrogen outlook and supply-chain delays
Renewable electricity capacity in the Middle East and North Africa (MENA) is forecast to more than double over the next six years, reaching almost 200 GW by 2031. The forecast is broadly unchanged from last year, with stronger corporate demand, project expansions and higher targets offsetting slower renewable hydrogen development and the impacts of near-term supply-chain and cost uncertainties linked to the closure of the Strait of Hormuz. These uncertainties may delay some planned projects but are not expected to weaken long-term ambitions or pipeline volumes.
Utility-scale solar PV leads renewable electricity growth in MENA, accounting for almost 80% of the 122 GW of capacity additions forecast for 2026-2031. Onshore wind contributes 13%, distributed solar PV 10%, and small additions from pumped-storage hydropower. By 2031, solar PV accounts for 75% of the region’s installed renewable capacity, the highest share of any region globally. This reflects targeted procurement and favourable economics supported by excellent resources, economies of scale from large projects and, in some markets, favourable land and state-backed financing conditions.
Rapid economic and population growth is a major driver of renewable electricity deployment in the region, with additional power demand coming from cooling, desalination, data centres, and low-emissions aluminium, steel and fertiliser production. Several major power systems, including those of Saudi Arabia, Egypt, Morocco, and Algeria, have recently recorded peak loads, while Oman has raised its demand outlook amid rapid growth in industrial and commercial consumption.
Energy security is another key growth driver, although motivations vary according to a country’s access to fossil fuels. In hydrocarbon-producing countries that can meet their power generation needs with domestic fuels, renewables reduce domestic fuel consumption, freeing up supplies for export. These markets account for roughly 67% of forecast growth, led by Saudi Arabia, which provides half of the regional increase (60 GW). Its renewable electricity targets support the Liquid Displacement Programme, which aims to make 1 million barrels of oil per day available for export by reducing domestic consumption. A record 9 GW was added in 2025, raising Saudi Arabia’s renewable electricity capacity to more than 14 GW. Similar drivers support expansion in other hydrocarbon-producing markets, including Oman.
Greater use of renewables also reduces import costs and exposure to price volatility and supply disruptions for hydrocarbon-importing countries – risks that the current conflict in the Middle East have further highlighted. Thus, around one-third of regional growth comes from countries that rely on fossil fuel imports for power generation, including Egypt and Tunisia, whose gas-fired power systems rely on imported gas; Morocco, which depends on coal and natural gas; and Iraq, where imported Iranian gas remains important for power generation. The United Arab Emirates is also a net gas importer despite being a major hydrocarbon producer.
The regional forecast is broadly unchanged from last year, as upward revisions in some markets offset reductions elsewhere. Egypt records the largest increase, reflecting accelerated renewable capacity plans after the current conflict in the Middle East caused a sharp rise in gas import costs. In March 2026, the government reported that the country’s monthly natural gas import bill had nearly tripled since the start of the conflict, from USD 560 million to USD 1.65 billion, and it moved its 45% renewable electricity target forward from 2035 to 2028. This acceleration builds on already-enacted reforms, including a new corporate power purchase agreement (PPA) framework, the reintroduction of competitive wind and solar auctions, and a growing pipeline of large bilateral wind, solar and storage projects.
The outlook for the United Arab Emirates has also been revised upwards, reflecting its plans to expand the Mohammed bin Rashid Al Maktoum Solar Park from 5 GW to more than 7 GW and the more ambitious clean energy targets. In January 2026, the country raised its clean energy target to 35% by 2031, up from 32% in 2030. Morocco’s forecast is similarly higher owing to a growing corporate PPA pipeline and faster-than-expected progress by OCP, the state-owned mining company, to realise its plan for more than 2 GW of renewable capacity, which supports its 2040 net zero target. Faster-than-expected growth in distributed solar PV for residential and off-grid applications in Syria also contributes to the upward revision. Unreliable electricity supply and high fuel costs have helped increase installed capacity from less than 500 MW in 2022 to over 2 GW in 2026.
However, slower-than-anticipated project progress in several markets and risks to project pipelines from closure of the Strait of Hormuz offset these gains. Supply-chain disruptions could delay equipment deliveries and construction, while uncertainty over equipment and insurance costs could weaken project economics and postpone final investment decisions (FIDs). The combined Chinese solar module imports of Saudi Arabia, the United Arab Emirates, Iraq, Jordan, Iran and Lebanon fell 61% year-on-year in the first three quarters of 2026, raising uncertainty over project delivery timelines.
One developer also reported that several financial closes and project-agreement signings could be delayed by 6-12 months. The forecast is therefore revised downwards for countries where projects are already progressing more slowly (Saudi Arabia) and where a significant share of the project pipeline has yet to reach FID (Iran and Iraq).
Oman’s forecast has also been scaled back from last year’s projections, mainly because of weaker prospects for renewable hydrogen. Two projects awarded in earlier hydrogen rounds were cancelled amid difficulties securing offtakers, while other awarded projects have yet to reach FID. Additionally, outlooks are lower for Libya and, to a lesser extent, Israel, where missed 2025 and 2026 renewable energy targets indicate slower-than-expected progress in advancing planned projects.
Note: The statistical data for Israel are supplied by and under the responsibility of the relevant Israeli authorities. The use of such data by the OECD is without prejudice to the status of the Golan Heights, East Jerusalem and Israeli settlements in the West Bank under the terms of international law.
Bilateral contracts between independent power producers and state-owned utilities are the main procurement route for renewable deployment in MENA, followed closely by competitive auctions. Together they account for over 80% of MENA’s utility-scale renewable capacity growth. This mainly reflects Saudi Arabia’s use of bilateral contracts sponsored by the Public Investment Fund (PIF), which cover 70% of the 130-GW 2030 target, with competitive procurements providing the remaining 30%.
Auctions remain the main procurement mechanism in the United Arab Emirates and Oman, and they have resumed in Egypt after a ten-year hiatus. Bilateral contracting is also gaining prominence, led by Egypt, while the United Arab Emirates and Oman have signed their first bilateral contracts for round-the-clock renewable power.
At the same time, direct corporate and industrial procurement is becoming an increasingly important source of renewable energy growth, particularly for low-emissions industrial production. In Egypt, exposure to the Carbon Border Adjustment Mechanism (CBAM) encourages aluminium, steel and silicon producers to procure their power supplies directly. In Morocco, most additions to the project pipeline stem from demand for industrial activities (notably OCP’s plans to decarbonise its mining and fertiliser operations and produce renewable ammonia) and for desalination and cement production. Corporate procurement is also emerging in Oman to supply renewable electricity to the oil and gas sector.
In the accelerated case, renewable energy expansion could be almost 30% higher – reaching nearly 233 GW by 2031 – if key regulatory, grid and financing barriers are addressed. As renewable penetration rises, system integration becomes increasingly important: one developer cited commissioning delays and claims for curtailment compensation caused by grid constraints. Countries are responding with planned grid upgrades and interconnections; greater battery storage deployment (Saudi Arabia, the United Arab Emirates, Egypt, Morocco and Oman); pumped-storage capacity and pipelines (Morocco, the United Arab Emirates, Israel, Egypt and Oman); and round-the-clock hybrid renewable projects (the United Arab Emirates and Oman).
Delivering these investments on or ahead of schedule could accelerate progress in realising existing renewable energy targets. Distributed solar PV could also expand more quickly if tariff and remuneration frameworks balance attractive economics for self-consumers with adequate grid cost recovery, alongside lower electricity subsidies. Weak offtaker creditworthiness, inflation and currency depreciation remain constraints in some markets, but state-backed guarantees, concessional financing and favourable contract terms could improve project bankability and accelerate deployment.
China’s renewable capacity forecast is revised down as slower solar PV growth outweighs upward revisions for onshore wind, hydropower and CSP
How much renewable electricity capacity is China forecast to add by 2031?
- China is forecast to add around 2 500 GW of renewable capacity over 2026–2031, 48% more than over 2020–2025.
- Annual renewable capacity additions reached a record 506 GW in 2025, 21% higher than in 2024. Over 2026–2031, annual additions are expected to average around 420 GW, almost 20% below the 2025 record.
- Solar PV is set to account for nearly three-quarters (74%) of renewable capacity additions over 2026–2031, followed by wind (22%) and hydropower (3%). Bioenergy, CSP, geothermal and ocean energy account for the remaining 1%.
Has the IEA revised its renewable electricity forecast for China compared to last year?
Summary: China’s renewable capacity forecast is revised down by 6% from last year’s edition, as downward revisions for solar PV (−12%), offshore wind (−35%) and bioenergy (−37%) outweigh upward revisions for onshore wind (+37%), hydropower (+12%) and CSP (+302%).
Solar PV: Growth is slowing sharply, with January–August additions 58% lower year-on-year. The forecast is revised down for utility-scale, commercial and industrial, and residential segments, as the shift from fixed tariffs to competitive auctions and greater wholesale market exposure have reduced project profitability and weakened the pipeline.
Onshore wind: Deployment remains resilient despite the shift from fixed-tariffs to competitive auctions, with January–August additions only 10% below last year’s record for the same period. The forecast is revised up as government policies seek to rebalance variable renewable deployment towards onshore wind, particularly through megabase projects, following rapid solar PV growth since 2023 and the resulting integration challenges. Wind capture prices also remain 30–40% higher than for solar PV, supporting stronger near-term revenue prospects.
Others: Policies addressing system integration also drive upward revisions for hydropower and CSP. For hydropower, approvals and construction of pumped-storage plants with 8–10 hours of storage have accelerated. For CSP, policies introduced in December 2025 then included in the 15th Five-Year Plan on Renewable Energy Development point to a more ambitious 2030 target of 15 GW, with stronger support to expand long-duration storage. Offshore wind is revised down as generation costs remain high relative to other technologies following the shift to market-based competitive auctions. Bioenergy additions have slowed since 2024 due to weaker growth in waste-to-energy projects.
What is driving renewable capacity growth in China?
Target: China’s long-term renewable expansion is underpinned by its 2060 carbon neutrality objective and the 2030 targets in the 15th Five-Year Plan on Renewable Energy Development. Published in July 2026, the plan targets 410 GW of conventional hydropower, 160 GW of pumped-storage hydropower, 15 GW of CSP and at least 2 800 GW of combined wind and solar PV capacity, surpassing 50% of total installed power capacity. It also targets 4 000 TWh of combined wind and solar PV generation and a 30% share of electricity generation from these technologies by 2030. By 2035, China aims to reach 3 600 GW of combined wind and solar PV capacity.
Provincial auctions: Provincial competitive renewable auctions using contracts for difference (CfDs) have already awarded more than 200 GW of onshore wind, utility-scale solar PV and distributed solar PV capacity.
Competitiveness: Auction prices for utility-scale and distributed renewables range from USD 30–50/MWh under 10–12-year contracts, below previous coal benchmark prices and current average wholesale electricity prices in almost all provinces.
Central policy: China’s renewable megabase policy supports large-scale onshore wind and solar PV projects in resource-rich inland areas, including the Gobi Desert and other northern and western regions, connected to coastal demand centres through high-voltage transmission infrastructure.
Enablers: Key enablers include low-cost financing; continued grid investment, including high-voltage direct current (HVDC) transmission; government support for pumped-storage hydropower and CSP to provide long-duration storage; and accelerating battery deployment to support near-term integration of variable renewables.
What are the main challenges to renewable capacity growth in China?
Revenue uncertainty: CfDs provide revenue certainty, but contract structures vary across provinces and limit the share of output eligible for the strike price. All renewable projects must participate in wholesale markets, exposing output beyond CfD coverage to price volatility.
Capture prices: In provinces with continuous wholesale market operations, solar PV capture prices average around USD 22/MWh (RMB 150/MWh), compared with around USD 30/MWh (RMB 200/MWh) for wind. Low capture prices and growing wholesale market exposure are weakening revenue prospects and the investment case for both technologies.
Curtailment: Rising wind and solar PV curtailment is reducing developer revenues and weakening project economics. Curtailment rates rose in 2025 to 5.7% for wind and 5.2% for solar PV and increased further in Q1 2026 to 8.1% and 8.8%, respectively, reaching 11–24% in Inner Mongolia West, Hainan, Hebei, Xinjiang and Henan.
Grid infrastructure: Despite significant investment in transmission and distribution networks, rapid deployment of utility-scale and distributed renewables, batteries, electric vehicles (EVs) and heat pumps requires continued network expansion. Distribution grid availability is expected to remain a constraint on faster renewable growth.
What would it take for China to achieve the IEA accelerated forecast?
In the accelerated case, China’s renewable capacity growth could be 13% higher than in the main case. The largest upside would come from solar PV, followed by onshore wind, pumped-storage hydropower and offshore wind.
Higher auction volumes: Provincial governments have awarded more than 200 GW of wind and solar PV capacity since CfD auctions were introduced. Larger auction volumes across provinces in 2027–2028 could support stronger capacity growth, while less restrictive CfD terms could improve revenue certainty for developers.
Faster market reform: Accelerated power market reform, cross-provincial trading of green energy certificates and expanded interprovincial power exchanges could improve wind and solar PV project economics and support higher deployment.
Faster battery adoption: Battery deployment is already accelerating, but a faster rollout would increase the value of wind and solar PV output, improve capture prices and strengthen project economics.
Grid expansion: Faster expansion of transmission and distribution networks would enable more renewable capacity to connect to the grid.
Growing corporate PPA market: Recent reforms allow large industrial users to sign direct power purchase agreements (PPAs) with developers, but the market remains small. Further regulatory reform and wider PPA uptake could reduce revenue uncertainty and improve project economics.
Faster hydropower project implementation: Accelerating the hydropower pipeline, particularly large pumped-storage projects, could add further renewable capacity.
Federal and state procurement accelerates Australia’s solar PV and onshore wind deployment, supported by battery storage
How much renewable electricity capacity is Australia forecast to add by 2031?
- Australia is forecast to add around 57.7 GW of renewable capacity over 2026–2031, 58% more than during 2020–2025.
- Australia’s annual renewable capacity additions reached around 6.8 GW in 2025, while large-scale and behind-the-meter battery storage additions were around 10 GWh and 5 GWh, respectively. Over 2026–2031, renewable capacity additions are expected to average around 9.6 GW per year.
- Over 2026–2031, solar PV is set to account for more than two-thirds (68%) of Australia’s renewable capacity additions, followed by onshore wind (27%) and pumped-storage hydropower (4%). Bioenergy accounts for a marginal share. Australia is also forecast to add over 60 GWh of behind-the-meter battery storage capacity.
Has the IEA revised its renewable electricity forecast for Australia compared to last year?
Summary: Australia’s renewable capacity forecast is revised up by around 31% compared with last year’s edition, with divergent trends across technologies. Pumped-storage hydropower (+42%), solar PV (+32%) and onshore wind (+17%) are revised up. Conventional hydropower and bioenergy are also revised up, with additions now at least offsetting expected decommissioning, while CSP is revised down to zero over the forecast period.
Solar PV: The solar PV forecast is revised up by around one-third, with stronger outlooks for both utility-scale and residential deployment. More than 6 GW of utility-scale solar PV has been awarded under the Capacity Investment Scheme (CIS), while state procurement and corporate offtakers provide further support. Recent market trends also point to robust growth in residential and small commercial installations. Increasing procurement of co-located and standalone utility-scale battery storage, together with government support for behind-the-meter batteries, improves system integration and self-consumption, strengthening the broader solar PV outlook.
Onshore wind: The onshore wind forecast is revised up by around 17%, reflecting a stronger project pipeline. The main drivers are around 10 GW of projects awarded under the CIS, together with state procurement schemes and corporate PPAs.
Others: Hydropower additions remain limited, but the forecast is revised up because of longer assumed lifetimes for existing projects.
What is driving renewable capacity growth in Australia?
Target: The federal objective of reaching 82% renewable electricity by 2030 remains the central policy signal. Australia’s 2025 emissions projections indicate that this would require almost 125 GW of renewable capacity by 2030.
Federal and state procurement: The expanded CIS is the main policy driver for utility-scale renewables, targeting 26 GW of renewable generation and 14 GW of clean dispatchable capacity by 2030. State auctions and renewable energy zone procurement complement the federal scheme.
Corporate PPAs and certificate demand: Corporate PPAs provide a complementary route to market for large-scale solar PV and onshore wind. However, as large-scale generation certificate prices decline, revenue certainty increasingly depends on long-term contracts.
Distributed PV and behind-the-meter batteries: Distributed PV remains attractive because of the gap between retail electricity prices and the declining cost of self-generated solar electricity. Government support strengthens the economics of self-consumption and combined solar PV and battery installations. The Cheaper Home Batteries Program indirectly supports rooftop PV by improving the economics of storing and self-consuming solar output, particularly as feed-in tariffs fall and export limits become more common. From October 2026, expanding the Small-scale Renewable Energy Scheme (SRES) to solar PV systems of up to 1 MW, from the previous 100 kW limit, is also expected to support additional growth in the mid-scale commercial PV segment.
Utility-scale battery storage: Utility-scale battery storage is becoming a central enabler of Australia’s renewables outlook, complementing strong growth in behind-the-meter batteries. Competitive procurement under the CIS and state tenders is accelerating the pipeline, with federal CIS rounds alone awarding more than 25 GWh of co-located storage and more than 35 GWh of standalone battery storage capacity. These projects provide dispatchable capacity, shift solar and wind generation to periods of higher demand, and reduce integration risks as coal-fired capacity retires.
What are the main challenges to renewable capacity growth in Australia?
Grid and transmission constraints: Transmission development remains a key system-level constraint on faster deployment. Congestion and delays to priority network projects increase revenue risks for new solar PV and wind projects.
Connection and permitting timelines: Lengthy grid-connection processes and planning approvals continue to delay utility-scale solar PV and onshore wind projects, limiting pipeline realisation.
Curtailment and revenue risk: Growing rooftop and utility-scale solar PV generation is increasing periods of low or negative wholesale prices and network-driven curtailment. This raises merchant revenue risk and strengthens the case for co-located batteries, flexible demand and faster transmission upgrades.
Distributed PV policy visibility: Declining support under the Small-scale Renewable Energy Scheme and Cheaper Home Batteries Program towards 2030, together with limited policy visibility beyond 2030, could affect distributed PV and behind-the-meter battery deployment, although further cost reductions may offset lower incentives. Commercial PV uptake will also depend on effective implementation of the expanded SRES eligibility.
What would it take for Australia to achieve the IEA accelerated forecast?
In the accelerated case, Australia’s renewable capacity growth could be around 12% higher than in the main case. The largest upside would come from solar PV, followed by onshore wind and pumped-storage hydropower, with smaller contributions from bioenergy and CSP.
High project realisation rates: Achieving the accelerated case would require high realisation rates for CIS and state tender awards, with projects moving faster from award to financial close, construction and commissioning.
Faster transmission and grid connection: The upside depends on timely delivery of renewable energy zones and priority transmission projects, alongside shorter connection processes and fewer system-strength constraints.
More storage, flexible demand and distributed PV integration: Battery deployment is already accelerating and shifting demand towards daytime hours by absorbing surplus solar generation. Achieving the accelerated case would require an even faster rollout of battery storage, pumped-storage hydropower, smart EV charging and flexible demand to further reduce curtailment and support project revenues. Stronger uptake of behind-the-meter batteries and smarter export arrangements would support continued rooftop PV growth.
Record solar PV deployment accelerates India’s renewable expansion and strengthens the forecast
How much renewable electricity capacity is India forecast to add by 2031?
- India is forecast to add almost 400 GW of renewable capacity over 2026–-2031, 2.6 times the capacity added during 2020–2025.
- India’s annual renewable capacity additions reached a record 59 GW in 2025, almost 70% above the 2024 level. Additions are expected to continue increasing, averaging around 67 GW per year and reaching around 74 GW by 2031.
- Over 2026–2031, solar PV is set to account for 83% of India’s renewable capacity additions, followed by wind (10%) and hydropower (6%). Bioenergy accounts for the remainder.
Has the IEA revised its renewable electricity forecast for India compared to last year?
Summary: India’s renewable capacity growth forecast is revised up by 10% compared with last year’s edition, with divergent trends across technologies. Solar PV (+15%) and pumped-storage hydropower (+8%) are revised up, while onshore wind (−14%), conventional hydropower (−20%) and bioenergy (−3%) are revised down.
Solar PV: Solar PV growth continues to accelerate, with additions from January to August 2026 more than 30% higher than during the same period last year. The forecast is revised up for both utility-scale and distributed applications. A large pipeline of auction-awarded projects and growing rooftop uptake, supported by national investment subsidies, underpin stronger growth.
Onshore wind: Onshore wind additions from January to August 2026 were over 10% lower than during the same period in 2025. The forecast is revised down because of limited dedicated auction volumes and growing competition from solar PV paired with battery storage, which is reducing wind’s role in some hybrid and firm-capacity projects.
Hydropower: The conventional hydropower forecast is revised down because construction delays are affecting several large projects. However, faster administrative procedures and an expanding project pipeline lead to an upward revision for pumped-storage hydropower.
What is driving renewable capacity growth in India?
Target: India targets 500 GW of non-fossil fuel electricity capacity by 2030, of which renewable capacity is expected to account for around 485 GW. The forecast expects India to meet this target. In 2025, the country achieved its objective of reaching a 50% share of non-fossil technologies in installed electricity capacity five years ahead of schedule. In April 2026, India submitted an updated NDC targeting a 60% share of non-fossil technologies in installed electricity capacity by 2035.
Renewable Purchase Obligations: Renewable Purchase Obligations (RPOs) require DISCOMs, open-access consumers and captive power producers to source a minimum share of electricity consumption from renewable technologies. The current trajectory raises the overall renewable energy consumption obligation from almost 30% in FY 2024/25 to more than 43% by FY 2029/30, with specific requirements for wind, hydropower and distributed renewable sources.
Auctions: Competitive auctions remain the main policy mechanism supporting utility-scale solar PV and wind expansion. Since India’s first renewable auction in 2010, around 220 GW of capacity has been awarded. Awards reached a record of more than 60 GW in 2024, but volumes slowed in 2025 and early 2026. Hybrid auctions combining solar PV, wind and storage with specific supply-profile requirements accounted for more than 60% of capacity awarded since 2024.
Distributed PV: Distributed solar PV capacity reached around 35 GW in 2025 and is expected to almost quadruple by 2031. Annual additions reached almost 10 GW in 2025, supported by improving economics and stronger policy support, particularly the PM Surya Ghar rooftop PV subsidy programme and the KUSUM scheme for agricultural applications.
Open-access procurement: Open access is an important driver of renewable capacity growth, particularly among commercial and industrial consumers, allowing large users to procure electricity directly from generators through bilateral contracts and third-party PPAs. Solar open-access additions increased from around 2.5 GW in 2022 to more than 7 GW in 2025. Overall, open-access projects account for around 15% of expected utility-scale solar PV and wind growth through 2031.
Competitiveness: India has achieved some of the world’s lowest renewable electricity prices. In 2026, average awarded tariffs reached around USD 25/MWh for standalone solar PV, USD 40/MWh for onshore wind and USD 50/MWh for hybrid projects with firm supply requirements, similar to average coal generation costs paid by DISCOMs. This competitiveness continues to support renewable procurement by utilities and large consumers.
System integration investments: India is accelerating investment in transmission networks, storage and hybrid projects. Utility-scale battery storage capacity is expected to increase from around 350 MW at the beginning of 2026 to 6–8 GW by 2031, while pumped-storage hydropower capacity doubles from around 7 GW to 14 GW. Firm-capacity auctions with higher capacity utilisation requirements are expected to facilitate faster variable renewable energy deployment.
PV supply chain expansion: India supports domestic solar PV manufacturing through measures including the Production Linked Incentive scheme, the Approved List of Models and Manufacturers (ALMM), and basic customs duties on imported modules and cells. Annual module manufacturing capacity consequently expanded from around 22 GW in 2022 to almost 150 GW in 2025, while cell capacity increased to around 27 GW. Further expansion could strengthen supply-chain resilience, increase the domestic economic benefits of renewable growth and support deployment, provided locally produced equipment remains cost-competitive.
What are the main challenges to renewable capacity growth in India?
DISCOM financial health: DISCOM financial performance remains a key challenge. In FY 2024/25, utilities responsible for almost 60% of electricity sales received Power Finance Corporation financial health ratings below A, while DISCOMs accounting for around one-quarter of sales received the lowest ratings of C, C− or D. As the main counterparties for renewable PPAs, DISCOM finances affect procurement, project bankability and investment conditions.
RPO monitoring and enforcement: Although RPOs are a major driver of renewable electricity demand, gaps in monitoring and enforcement can delay procurement and PPA signing.
Variable renewable integration: Investment in transmission, storage and hybrid systems is accelerating. However, renewable capacity expansion could outpace improvements in system flexibility in some regions, increasing grid congestion and curtailment risks.
Domestic PV equipment availability: India is aligning renewable capacity growth with domestic supply-chain development, particularly for solar PV. Timely availability of cost-competitive domestic equipment that meets regulatory requirements will be important to sustain deployment.
What would it take for India to achieve the IEA accelerated forecast?
In the accelerated case, India’s renewable capacity could be 22% higher than in the main case. The largest upside would come from utility-scale solar PV, followed by distributed solar PV, onshore wind and pumped-storage hydropower.
Higher auction volumes: After record capacity awards in 2024, auction volumes slowed considerably in 2025 and early 2026. Higher auction volumes, regular procurement schedules and faster PPA signing for awarded projects would strengthen the pipeline and support faster capacity growth.
Improved DISCOM financial health: Stronger DISCOM finances would reduce perceived offtaker risks, lower financing costs and accelerate renewable PPA signing. They would also support investment in rooftop PV, distribution networks and flexibility measures needed to integrate higher shares of variable renewables.
Faster battery deployment and grid expansion: Battery deployment is already accelerating, but faster growth would increase system flexibility, reduce integration challenges and enable higher solar PV and wind penetration. Faster transmission and distribution network expansion would reduce connection delays and allow more renewable projects to come online.
Lower barriers for open-access consumers: Streamlining approval procedures and optimising charges for open-access consumers could accelerate renewable procurement by commercial and industrial users through bilateral contracts, captive projects and third-party PPAs.
Faster hydropower project implementation: Shorter permitting timelines, faster construction and streamlined approvals, particularly for pumped-storage hydropower, could add renewable capacity and improve power system flexibility.
Stronger support for residential rooftop PV: Sustained policy support, greater consumer awareness, better access to financing, and simpler administrative and grid-connection procedures could accelerate residential adoption.
Faster solar PV and geothermal deployment strengthens Indonesia’s renewable forecast, although grid and market constraints remain
How much renewable electricity capacity is Indonesia forecast to add by 2031?
- Indonesia is forecast to add 41 GW of renewable capacity over 2026–2031, almost eight the capacity added during 2020–2025.
- Indonesia’s annual renewable capacity additions reached almost 2 GW in 2025, more than double the 2024 level. Over 2026–2031, additions are expected to average around 7 GW per year.
- Over 2026–2031, solar PV is set to account for 78% of Indonesia’s renewable capacity additions, followed by hydropower (9%), wind (6%), geothermal (3%) and bioenergy (3%).
Has the IEA revised its renewable electricity forecast for Indonesia compared to last year?
Summary: Indonesia’s renewable capacity forecast is revised up by two thirds compared to last year’s level, with divergent trends across technologies. Solar PV (+116%) and geothermal (+41%) are revised up, while onshore wind (−9%) and hydropower (−26%) are revised down.
Solar PV and geothermal: Upward revisions reflect improved policy frameworks and stronger project pipelines. Revised PPA arrangements, faster permitting and robust commercial and industrial demand support solar PV deployment, while targeted government measures streamline geothermal project development.
Hydropower and wind: Downward revisions reflect persistent project delays and structural constraints. Hydropower projects face long development timelines, permitting challenges and social acceptance issues, while wind deployment is constrained by a weaker project pipeline and slower progress towards financial close.
What is driving renewable capacity growth in Indonesia?
Targets: Indonesia’s 100 GW Solar Power Programme targets the deployment of 100 GW of cumulative solar PV capacity by around 2029, supported by battery energy storage systems. In parallel, covering a wider range of renewable technologies, Indonesia’s Electricity Supply Business Plan (RUPTL 2025–2034) targets 69.5 GW of new power capacity by 2034, of which 76% is planned to come from renewable sources and storage (around 43 GW of renewables and 10 GW storage). Solar PV, hydropower and wind lead additions, in line with the country’s net zero emissions target by 2060.
Improved contracting framework: The revised renewable PPA framework (MEMR 5/2025) improves long-term visibility and contractual certainty for developers, strengthening project bankability and private-sector participation.
Solar PV expansion: Rooftop solar quotas, with around 5.7 GW planned for 2024–2028, and strong commercial and industrial demand drive solar PV growth, making it the largest contributor to near-term capacity additions.
Government support and international financing: Measures to streamline permitting, improve project economics and mobilise financing, particularly for geothermal, support additional project development.
What are the main challenges to renewable capacity growth in Indonesia?
Grid constraints and system integration: Underinvestment in transmission infrastructure and limited system flexibility constrain the integration of new renewable capacity, while grid bottlenecks and connection delays remain key barriers.
Existing fossil fleet: A large, relatively young coal fleet operating under long-term contracts limits incentives to procure and invest in renewable generation. Substantial financial obligations and dependence on government support also constrain the ability to expand renewable procurement, transmission infrastructure and system flexibility at the pace required for a faster energy transition.
Policy uncertainty and market design: Evolving policy frameworks, limited institutional co-ordination and remaining regulatory gaps, including for storage and distributed PV, may weigh on investor confidence and slow project development.
What would it take for Indonesia to achieve the IEA accelerated forecast?
In the accelerated case, renewable capacity additions in Indonesia could be around 50% higher than in the main case. Geothermal and wind offer the largest upside potential, followed by solar PV and bioenergy.
Faster grid expansion and greater system flexibility: Increased investment in transmission and storage would enable greater integration of solar PV and other variable renewables, supporting project pipeline realisation.
Stronger financing and project de-risking: Mobilising additional public and private capital, alongside stronger project bankability and contractual frameworks, would accelerate investment.
Scaling up solar PV deployment: Expanding distributed and utility-scale solar PV, supported by higher quotas, storage integration and continued corporate demand, would drive faster capacity growth. Effective implementation of existing measures, including PPA frameworks, quotas and potential direct PPA mechanisms, would improve project execution and pipeline realisation.
Japan’s renewable growth shifts towards distributed solar PV as utility-scale deployment faces implementation challenges
How much renewable electricity capacity is Japan forecast to add by 2031?
- Japan is forecast to add over 51 GW of renewable capacity over 2026–2031, 11% less than during 2020–2025.
- Japan’s annual renewable capacity additions reached 7.3 GW in 2025, around 11% below the 2024 level. Over 2026–2031, additions are expected to average around 8.6 GW per year.
- Over 2026–2031, solar PV is set to account for around three-quarters (75%) of Japan’s renewable capacity additions, followed by wind (18%) and bioenergy (3%). Geothermal and hydropower together account for the remaining 4%.
Has the IEA revised its renewable electricity forecast for Japan compared to last year?
Summary: Japan’s renewable capacity forecast is revised down by 12% compared with last year’s edition, with divergent trends across technologies. Onshore wind (−39%), offshore wind (−21%) and solar PV (−6%) are revised down, while hydropower (+95%, from a small base), bioenergy (+51%) and geothermal (+7%) are revised up.
Solar PV: Solar PV is revised down moderately, mainly because policy support is shifting from new ground-mounted projects, which are typically utility-scale, towards rooftop systems, which are generally distributed. The planned phase-out of administratively set and auction-based FIT/FIP support for new ground-mounted solar PV projects of 10 kW or more from FY2027, together with local opposition and stricter engagement requirements, weighs on the utility-scale outlook. Distributed solar PV remains more resilient, supported by rooftop mandates, continued FIT/FIP support and self-consumption economics in the commercial and residential sectors, although recent deployment has been below previous expectations.
Onshore wind: Onshore wind is revised down sharply because many projects in the pipeline continue to face delays. Deployment in 2025 was significantly below previous expectations, reflecting persistent permitting delays, local opposition, grid-connection constraints and higher capital costs. As a result, we do not expect a large share of legacy FIT-certified projects to be commissioned by 2031.
Offshore wind: Offshore wind is revised down because of project delays, cancellations and continued execution risks related to permitting, grid connection and rising costs. Several awarded projects remain in the forecast, but delivery depends on whether additional measures, including long-term revenue support, can improve bankability. The government has also revised offshore wind auction rules to avoid overly aggressive bids and strengthen project delivery. However, re-tendered Round 1 sites and future Round 4 projects are not expected to be commissioned before 2031.
Others: Bioenergy is revised up, reflecting stronger recent deployment, a sizeable FIT-certified pipeline and growing corporate PPA activity, while hydropower and geothermal are revised up from smaller bases.
What is driving renewable capacity growth in Japan?
Long-term energy plan: The outlook for Energy Supply and Demand in FY2040, published alongside Japan’s 7th Strategic Energy Plan, projects that renewables will become a major power source and account for approximately 40–50% of electricity generation. For 2030, deployment remains benchmarked against the 6th Strategic Energy Plan, equivalent to around 187 GW of renewable capacity (AC for solar PV).
Support schemes: FIT/FIP support, including competitive auctions for larger projects, remains the main policy route for new utility-scale solar PV and onshore wind, although its role is narrowing. From FY2027, new ground-mounted solar PV projects of 10 kW or more are expected to lose access to FIT/FIP support as the government prioritises rooftop projects with fewer land-use conflicts. Residential and commercial rooftop systems remain eligible, supporting the shift towards distributed deployment. Onshore wind also remains eligible, but recent auction undersubscription indicates weaker investor appetite under current permitting, cost and grid conditions.
Distributed solar PV mandates: Tokyo and Kawasaki started requiring solar PV on many new buildings in 2025, creating a clearer route for rooftop deployment in dense urban areas where large-scale ground-mounted projects face land constraints and local opposition.
Market-based drivers: Corporate PPAs are becoming a more important driver for Japan’s renewable capacity growth as FIT/FIP support for new ground-mounted solar PV phases out.
What are the main challenges to renewable capacity growth in Japan?
Permitting and local acceptance: Local opposition is a key cause of permitting delays for larger projects, particularly ground-mounted solar PV and wind. New community-engagement requirements, including mandatory meetings with local residents, aim to improve acceptance over time but are also likely to lengthen near-term development timelines.
Project economics: Higher costs are weakening wind project economics. Offshore wind projects remain exposed to implementation risk because some zero-subsidy bids provide limited revenue certainty under the current support framework. Projects may therefore depend on corporate PPAs or additional long-term revenue support to reach financial close.
Curtailment: Curtailment has become a challenge in several regions, reducing revenue certainty and weakening bankability. The expected change in curtailment order, under which FIT projects would be curtailed before FIP projects, could increase revenue risk for legacy FIT assets.
What would it take for Japan to achieve the IEA accelerated forecast?
In the accelerated case, Japan’s renewable capacity additions could be 31% higher than in the main case. The largest upside would come from solar PV, followed by onshore wind, offshore wind, bioenergy, geothermal and hydropower.
Faster distributed PV growth: Stronger implementation of rooftop mandates, continued support for commercial and residential PV, greater self-consumption and wider corporate PPA uptake would help offset slower ground-mounted utility-scale PV deployment after FIT/FIP support for new ground-mounted solar PV projects of 10 kW or more ends in FY2027.
Improved project realisation: Faster permitting, stronger local acceptance, clearer grid-connection timelines and more stable project economics would enable a larger share of the certified onshore wind and utility-scale solar PV pipeline to be commissioned by 2031.
Restored offshore wind investor confidence: The accelerated case would require timely re-tendering of Round 1 sites and quick implementation of the revised offshore wind framework, including stronger delivery requirements.
Grid reinforcement and curtailment management: Faster grid investment, better inter-regional interconnection lines and clearer curtailment rules would improve revenue certainty for wind and solar projects and support higher deployment in regions where grid constraints are already limiting output.
Stronger corporate PPA market: Wider adoption of corporate PPAs would help support projects with lower or no subsidy support, especially utility-scale solar PV.
Higher solar PV ambition and stronger deployment accelerate Korea’s renewable growth
How much renewable electricity capacity is Korea forecast to add by 2031?
- Korea is forecast to add over 45 GW of renewable capacity over 2026–2031, 55% more than during 2020–2025.
- Korea’s annual renewable capacity additions reached 4.8 GW in 2025. Over 2026–2031, additions are expected to average around 7.6 GW per year.
- Over 2026–2031, solar PV is set to account for 88% of Korea’s renewable capacity additions, followed by wind (10%). Bioenergy and hydropower together account for the remaining 2%.
Has the IEA revised its renewable electricity forecast for Korea compared to last year?
Summary: Korea’s renewable capacity forecast is revised up by around 75% compared with last year’s edition, with divergent trends across technologies. Solar PV (+97%) and onshore wind (+46%) are revised up, while offshore wind (−41%) and bioenergy (−8%) are revised down. Hydropower is also revised up and is now expected to offset decommissioning.
Solar PV: Solar PV is revised up significantly reflecting stronger-than-expected additions in 2025, continued auction activity, growing corporate demand for renewable electricity and higher policy ambition, including the 87 GW solar PV capacity target released in May 2026.
Onshore wind: Onshore wind is revised up from around 1.1 GW to 1.6 GW over 2026–2030, supported by larger fixed-price auction activity and a stronger policy focus on planned siting.
Offshore wind: Offshore wind is revised down from 2.8 GW to 1.7 GW because of permitting, grid-connection and project-execution delays. Although the new offshore wind framework is expected to improve project development, its impact on commissioning before 2031 remains limited.
Others: Hydropower is revised up modestly and is now expected to offset decommissioning, while the bioenergy forecast is revised down slightly.
What is driving renewable capacity growth in Korea?
Target: Korea’s first Basic Plan for Renewable Energy targets 100 GW of cumulative renewable capacity by 2030, including 87 GW of solar PV, and aims to raise renewables’ share of power generation to at least 30% by 2035.
Solar-led pipeline: Solar PV remains the main growth driver, supported by large utility-scale projects, rooftop and distributed PV, floating solar and agrivoltaics. Government plans for mega solar complexes and greater use of industrial rooftops are expected to support further deployment.
Auction and support-scheme reform: Korea continues to hold fixed-price renewable auctions and is advancing reforms to replace the RPS/REC framework with a government-led auction and long-term contract mechanism, improving revenue visibility for renewable projects.
Corporate PPAs and merchant projects: Growing RE100 demand is increasing the role of corporate PPAs, although uptake remains constrained by grid charges, ancillary costs and limited market flexibility.
What are the main challenges to renewable capacity growth in Korea?
Grid constraints and curtailment: Grid congestion is increasing in resource-rich regions. Rising curtailment and connection delays are extending project commissioning timelines and weighing on the forecast.
Revenue certainty and transition risk: The transition from RPS/REC-based support to auctions and long-term contracts is expected to improve project bankability, but implementation details remain uncertain. Projects outside auction volumes face greater merchant exposure, while the corporate PPA market remains limited.
Permitting and siting: Land availability, local acceptance and permitting continue to constrain onshore wind, offshore wind and utility-scale solar PV. The new offshore wind law introduces government-led zoning and a one-stop permitting process, but its impact will depend on effective implementation.
Auction delivery: Larger renewable auction volumes support the forecast, but undersubscription, supply-chain and security requirements, and rising development costs could limit participation or delay project delivery.
What would it take for Korea to achieve the IEA accelerated forecast?
In the accelerated case, Korea’s renewable capacity additions could be around 23% higher than in the main case. The largest upside would come from solar PV, followed by onshore and offshore wind, hydropower and bioenergy.
Effective permitting and siting reforms: Faster implementation of planned siting reforms, one-stop permitting for offshore wind and streamlined approval processes would accelerate solar PV and wind deployment.
Stronger revenue certainty: Faster implementation of government-backed long-term contracts, clearer RPS/REC transition rules and a more accessible corporate PPA framework, including transparent grid charges and broader offtaker participation, would improve project economics.
Faster grid expansion and lower curtailment: The accelerated case requires faster transmission and distribution investment and quicker deployment of storage and flexible demand to reduce curtailment risk.
Faster connection and project execution: Shorter grid-connection timelines and more efficient queue management would enable a larger share of the solar PV and wind pipeline to be commissioned before 2031.
Record solar PV deployment in 2026 and a rapidly expanding pipeline strengthen New Zealand’s renewable forecast
How much renewable electricity capacity is New Zealand forecast to add by 2031?
- New Zealand is forecast to add around 9.8 GW of renewable capacity over 2026–2031, more than five times the capacity added during 2020–2025.
- New Zealand’s annual renewable capacity additions reached 0.5 GW in 2025, 22% below the 2024 level. Over 2026–2031, additions are expected to average around 1.6 GW per year.
- Over 2026–2031, solar PV is set to account for around 88% of New Zealand’s renewable capacity additions, followed by wind (7%). Geothermal and hydropower together account for the remaining 5%.
Has the IEA revised its renewable electricity forecast for New Zealand compared to last year?
Summary: New Zealand’s renewable capacity forecast is revised up by 104% compared with last year’s edition, with divergent trends across technologies. Solar PV (+135%) and geothermal (+41%) are revised up, while onshore wind (−9%) is revised down.
Solar PV: Solar PV is revised up significantly, from 3.0 GW to 7.0 GW over 2026–2030, reflecting stronger-than-expected utility-scale and distributed PV deployment in 2025 and continued rapid growth in 2026. By September 2026, almost 600 MW of utility-scale PV had been commissioned during the year.
Onshore wind: Onshore wind is revised down from around 0.63 GW to 0.57 GW over 2026–2030, reflecting slower progress and a slightly weaker pipeline than previously expected.
Others: Geothermal is revised up from 0.2 GW to 0.3 GW over 2026–2030, reflecting stronger recent deployment and a larger project pipeline in the grid-connection queue.
What is driving renewable capacity growth in New Zealand?
Ambition: The government’s Electrify New Zealand programme aims to double renewable electricity generation by 2050. As a nearer-term planning benchmark, MBIE’s Electricity Demand and Generation Scenarios 2024 indicate almost 12 GW of renewable capacity by 2030.
Distributed PV: Distributed PV becomes the main source of renewable capacity growth after 2026, led by commercial installations, while residential deployment also accelerates. Commercial uptake is driven mainly by self-consumption savings, with retailer buy-back offers providing additional revenue for surplus electricity. Reforms introduced in 2026 simplify installations and standardise connection and export-limit processes, while time-varying offers and peak-period network rebates support households and eligible small businesses.
Utility-scale solar PV: Record commissioning drives the initial step-up in 2026. Further growth is supported by a rapidly expanding project pipeline and prospective demand from electrification, industrial facilities and data centres.
What are the main challenges to renewable capacity growth in New Zealand?
Project realisation: The forecast depends on a marked increase in project conversion rates, as only a limited share of the much larger development pipeline has reached final investment decision or construction. Securing consents, financing and construction capacity will determine how quickly proposed projects are commissioned.
Market revenues: Most new projects remain exposed to wholesale market revenues without access to government-backed long-term contracts. As solar penetration rises, concentrated daytime generation could reduce capture prices, increasing the importance of corporate PPAs, storage and flexible demand for project bankability.
Grid connection: Long connection and network-development timelines could delay commissioning across the expanding project pipeline.
What would it take for New Zealand to achieve the IEA accelerated forecast?
In the accelerated case, New Zealand’s renewable capacity additions could be almost 40% higher than in the main case. The largest upside would come from solar PV, followed by onshore wind and geothermal.
Faster project delivery: Shorter consenting and connection timelines, including effective use of the fast-track regime, would enable a larger share of the solar PV and wind pipeline to reach financial close, construction and commissioning.
Stronger distributed PV uptake: Faster implementation of simplified connection processes and more attractive export arrangements would accelerate household and commercial installations.
More system flexibility: Faster grid expansion, battery deployment and flexible demand would support higher shares of variable renewables and limit curtailment.
Consumer-led solar PV reshapes Pakistan’s renewable forecast
How much renewable electricity capacity is Pakistan forecast to add by 2031?
- Pakistan is forecast to add 73 GW of renewable capacity over 2026–2031, 2.3 times the capacity added during 2020–2025.
- Annual renewable capacity additions reached 10 GW in 2025, almost 10% above the 2024 level, and are forecast to average around 12 GW per year over 2026–2031.
- Solar PV is set to provide 86% of Pakistan’s renewable capacity additions over 2026–2031, followed by hydropower (11%) and onshore wind (2%).
Has the IEA revised its renewable electricity forecast for Pakistan compared to last year?
Summary: Pakistan’s renewable capacity growth forecast is 13% higher than in last year’s edition, mainly reflecting stronger-than-expected distributed solar PV growth (+18%). High electricity tariffs and demand for more reliable supply continue to support consumer investment in solar PV systems. This increase is partly offset by a 20% downward revision for utility-scale solar PV due to financing challenges, grid connection constraints and long project development timelines.
What is driving renewable capacity growth in Pakistan?
Target: Pakistan’s Indicative Generation Capacity Expansion Plan (IGCEP 2025) targets more than 31 GW of cumulative renewable capacity by 2030, including almost 17 GW of hydropower, 9.4 GW of solar PV and 4 GW of onshore wind. Growth is forecast to significantly exceed this trajectory as rapid consumer-led distributed solar PV deployment more than offsets weaker-than-expected onshore wind additions. Hydropower development is expected to remain broadly in line with IGCEP assumptions.
Distributed and off-grid solar PV: Distributed solar PV is the main driver of Pakistan’s renewable capacity expansion. High electricity tariffs, frequent power supply interruptions and rapidly declining solar PV module prices are encouraging households, commercial users and industry to install systems that lower electricity costs and improve supply reliability. Strong growth in solar PV imports from China indicates that more than 20 GW has been installed in unregistered off-grid applications.
Hydropower development: Large-scale hydropower remains an important source of renewable electricity growth. Projects under construction, including major reservoir and run-of-river plants, are expected to add 8 GW over the forecast period, providing dispatchable renewable generation and greater power system flexibility.
What are the main challenges to renewable capacity growth in Pakistan?
Power-sector financial constraints: Weak financial performance of electricity distribution companies and payment risks remain important barriers to investment in utility-scale renewable projects.
Transmission system capacity: Limited transmission infrastructure constrains the integration of new renewable projects, particularly utility-scale solar PV and wind resources located far from demand centres.
Uncertainty over utility-scale procurement: Despite strong solar PV resource potential, utility-scale solar PV and wind deployment remains limited by delays to competitive auctions and uncertainty over long-term procurement.
VRE system integration needs: Rapid distributed solar PV growth increases the need for stronger distribution network management, digitalisation and flexibility. Greater visibility of behind-the-meter capacity, alongside storage deployment and updated grid operating practices, will be needed as solar PV penetration rises.
What would it take for Pakistan to achieve the IEA accelerated forecast?
In the accelerated case, Pakistan’s renewable capacity growth could be almost 20% higher than in the main case. Distributed solar PV offers the largest upside potential, followed by hydropower, onshore wind and utility-scale solar PV.
Launching competitive renewable auctions: Regular, transparent competitive auctions would accelerate utility-scale solar PV and wind deployment by improving long-term revenue visibility and attracting private investment.
Improving grid infrastructure and system flexibility: Expanding transmission and distribution networks, improving visibility of distributed solar PV and increasing flexibility through storage and demand response would enable higher shares of variable renewable electricity.
Strengthening power-sector finances: Reducing payment risks and improving distribution company finances would lower investment risk and financing costs, supporting faster renewable project development.
New market mechanisms and rooftop solar support strengthen Thailand’s renewable forecast, but implementation remains critical
How much renewable electricity capacity is Thailand forecast to add by 2031?
- Thailand is forecast to add 15 GW of renewable capacity over 2026–2031, more than three times the capacity added over 2020–2025.
- Annual renewable capacity additions reached almost 3 GW in 2025, almost four times the 2024 level, and are forecast to average around 2.5 GW per year over 2026–2031.
- Solar PV is set to provide 80% of Thailand’s renewable capacity additions over 2026–2031, followed by wind (19%), with other technologies accounting for the remaining 1%.
Has the IEA revised its renewable electricity forecast for Thailand compared to last year?
Summary: Thailand’s renewable capacity growth forecast is more than 45% higher than in last year’s edition, although revisions vary by technology. Solar PV (+60%) and wind (+23%) are revised upwards, while hydropower (-98%) and bioenergy (-36%) are revised downwards, due to slower project delivery.
Solar PV: The upward revision reflects faster implementation of utility-scale projects awarded in earlier procurement rounds and stronger distributed solar PV growth, supported by new net-billing provisions and rising corporate demand from data centres and other emerging industries.
Hydropower: The downward revision reflects a limited project pipeline, with only a small number of hydropower plants forecast to be commissioned before 2031.
What is driving renewable capacity growth in Thailand?
Target: Thailand’s long-term energy planning provides strategic direction for renewable deployment, although some elements remain in draft form. The National Energy Plan framework targets renewables to provide at least 50% of new electricity generation.
Competitive procurement and FIT programme: The 2022–2030 FiT programme, commissioning of capacity awarded in earlier procurement rounds and new rooftop solar PV net-billing provisions support both utility-scale and distributed renewable deployment.
Expanded distributed solar PV support: A new rooftop solar PV net-billing scheme, including a ten-year feed-in tariff for exported electricity, supports residential and small-scale deployment.
Direct PPA mechanism: A pilot scheme launched in 2026 enables large consumers, particularly data centres, to procure renewable electricity directly, supporting corporate demand and commercial solar PV development.
Rising demand from new industries: Investment in digital infrastructure and data centres is increasing demand for clean electricity, supporting utility-scale and distributed renewable capacity additions.
What are the main challenges to renewable capacity growth in Thailand?
Grid connection and project delivery: Grid-connection constraints and delays continue to slow the commissioning of awarded solar PV and wind projects.
Permitting and implementation delays: Lengthy permitting procedures, delays in finalising PPAs and other implementation bottlenecks continue to extend project timelines.
Limits on direct electricity sales: Although direct PPAs have been introduced, restrictions on third-party access and power trading constrain market expansion and private-sector participation.
Competition with existing generation: A relatively young conventional generation fleet operating under long-term contracts may limit power system flexibility and slow renewable integration.
What would it take for Thailand to achieve the IEA accelerated forecast?
In the accelerated case, Thailand’s renewable capacity additions could be around one-quarter higher than in the main case, with similar upside potential for solar PV, onshore wind and bioenergy.
Faster grid investment and permitting: Accelerating transmission and distribution investment, streamlining connection procedures and shortening approval timelines would unlock more of the project pipeline and improve delivery rates.
Broader direct PPA market: Expanding the direct PPA framework beyond the pilot and improving third-party access rules would strengthen corporate demand and private investment.
Faster implementation of support schemes: Timely delivery of FiT-awarded projects and faster uptake of rooftop solar PV programmes would boost near-term deployment.
Greater system flexibility: Expanding storage, improving system operations and increasing flexibility would support higher shares of solar PV and wind.
Viet Nam sets higher renewable targets under PDP8, but timely implementation remains critical
How much renewable electricity capacity is Viet Nam forecast to add by 2031?
- Viet Nam is forecast to add almost 54 GW of renewable capacity over 2026–2031, more than twice the capacity added during 2020–2025.
- Annual renewable capacity additions reached over 2 GW in 2025, increasing by more than 40% from 2024, and are forecast to average around 9 GW per year over 2026–2031 as increasingly large volumes of solar PV and onshore wind come online.
- Solar PV is set to provide around 52% of Viet Nam’s renewable capacity additions over 2026–2031, followed by wind (42%), hydropower (5%) and bioenergy (1%).
Has the IEA revised its renewable electricity forecast for Viet Nam compared to last year?
Summary: Viet Nam’s renewable capacity growth forecast is broadly unchanged (+1%) compared with last year’s edition, with upward revisions for solar PV (+20%), while downward revisions in onshore wind (-3%) and hydropower (-57%).
Hydropower: The downward revision reflects delayed construction starts at the Dong Phu Yen and Lam Son hydropower plants, pushing commissioning beyond the forecast period.
What is driving renewable capacity growth in Viet Nam?
Target: Viet Nam’s revised Eighth Power Development Plan (PDP8) targets 46–73 GW of solar PV, 26–38 GW of onshore and nearshore wind, 1.5–2.7 GW of biomass and 1.4–2.1 GW of waste-to-energy capacity by 2030, alongside 6–17 GW of offshore wind between 2030–2035.
Electricity demand growth: Expanding manufacturing and industrial activity, alongside rising electrification, is increasing electricity demand and the need for new generation, grid infrastructure and system flexibility.
Direct Power Purchase Agreements (DPPAs): The framework under Decree 57/2025 enables large consumers to procure renewable electricity directly through private-wire or grid-connected arrangements, providing an alternative market-based route for renewable electricity procurement and supporting solar PV and wind deployment. Subsequent measures clarify contractual models, eligibility and cost structures.
Local manufacturing and engineering: Investment in solar PV wafer, cell and module production reinforces Viet Nam’s role as a regional manufacturing hub. Established industrial and offshore engineering capabilities also provide a foundation for future wind deployment.
What are the main challenges to renewable capacity growth in Viet Nam?
Grid infrastructure and congestion: Transmission expansion has not always kept pace with renewable deployment. Timely delivery of the grid investments in revised PDP8, alongside greater storage and system flexibility, will be critical to integrating rising solar PV and wind capacity, particularly in resource-rich regions.
Nearshore wind: Achieving Viet Nam’s targets will require clearer marine spatial planning, permitting and project-award mechanisms. Regulatory certainty remains essential to investor confidence and timely delivery of initial projects.
Limited rooftop solar PV support: The current framework permits self-produced and self-consumed rooftop solar PV, with limited surplus sales to the grid. However, support for distributed installations remains relatively weak following the expiry of earlier feed-in tariffs.
Project development and permitting: Large renewable and storage projects face lengthy land, environmental, grid-connection and investment approval procedures, slowing project delivery despite strong policy targets.
What would it take for Viet Nam to achieve the IEA accelerated forecast?
In the accelerated case, Viet Nam’s renewable capacity additions could be 33% higher than in the main case. Solar PV and wind offer the largest upside potential, followed by bioenergy, hydropower and geothermal.
Faster grid expansion and greater system flexibility: Accelerating transmission investment and improving grid utilisation, storage and flexibility would support higher shares of solar PV and wind while reducing congestion risks.
Faster implementation of PDP8: Streamlining permitting, land allocation and project approvals, particularly for wind and hydropower, would accelerate deployment.
Scaling up market-based procurement: Transparent procurement mechanisms and a bankable offshore wind framework would mobilise greater private investment and accelerate utility-scale solar PV and wind deployment.
Support for household solar PV: Draft proposals for 2026–2030 include capital support for rooftop solar PV and paired storage, alongside preferential household loans. If approved, these measures would strengthen distributed solar PV deployment.
Distributed solar PV drives Belgium’s renewable expansion as offshore wind delays weigh on growth
How much renewable electricity capacity is Belgium forecast to add by 2031?
- Belgium is forecast to add 8 GW of renewable capacity over 2026-2031, 5% less than over 2020-2025.
- Annual renewable capacity additions reached 1.1 GW in 2025, stable from 2024, and are expected to average around 1.3 GW per year over 2026-2031.
- Solar PV accounts for 81% of renewable capacity additions over 2026-2031, followed by onshore wind at 18%.
Has the IEA revised its renewable electricity forecast for Belgium compared to last year?
Summary: Belgium’s renewable capacity growth forecast is revised down by almost 10% from last year’s edition, mainly because delays in organising the planned offshore wind auction push previously expected capacity beyond the forecast period.
What is driving renewable capacity growth in Belgium?
Target: Belgium’s National Energy and Climate Plan (NECP) targets a 48.5% renewable share in electricity generation by 2030, requiring almost 14 GW of solar PV, 4.8 GW of onshore wind and 5.7 GW of offshore wind capacity. The forecast exceeds the solar PV ambition on the back of strong distributed PV growth, but falls short of onshore and offshore wind targets owing to policy delays and slower permitting and project development.
Distributed solar PV: Distributed solar PV remains the main driver of renewable capacity growth, supported by high retail electricity prices, declining technology costs and self-consumption incentives. Regional policies have been instrumental, including net billing in Flanders and Wallonia, green certificates in Brussels and investment support. Although annual additions are expected to moderate from the 2023 record, high retail prices continue to underpin favourable economics for residential and commercial consumers.
Offshore wind: Offshore wind remains central to Belgium’s long-term renewable strategy, but no new capacity has been commissioned since the first development phase was completed in 2020. A contract-for-difference (CfD) mechanism approved in 2024 supports the next phase in the Princess Elisabeth Zone, with an estimated potential of 3.5 GW. However, auction delays have pushed back expected commissioning dates, shifting part of the planned capacity beyond 2031.
What are the main challenges to renewable capacity growth in Belgium?
Permitting and land availability: High population density, competing land uses and complex permitting procedures continue to constrain utility-scale solar PV and onshore wind development.
Limited transmission system capacity: Offshore wind expansion depends on the timely completion of transmission infrastructure, including the Princess Elisabeth Island energy hub, while distribution grids require upgrades to accommodate rising distributed solar PV capacity.
VRE system integration needs: Rising shares of solar PV and wind are increasing flexibility needs. Faster deployment of battery storage, demand response and grid digitalisation will be required to manage periods of high renewable output and support further integration of variable renewables.
What would it take for Belgium to achieve the IEA accelerated forecast?
In the accelerated case, Belgium’s renewable capacity could be almost 40% higher than in the main case, with the largest upside from distributed solar PV, followed by utility-scale PV and offshore wind.
Enhancing support for distributed solar PV: Maintaining attractive self-consumption economics, accelerating battery storage adoption and supporting collective self-consumption models could boost distributed PV deployment, with further potential from commercial and industrial consumers.
Accelerating offshore wind development: Timely offshore wind auctions, faster permitting and completion of associated grid infrastructure, including the Princess Elisabeth Island energy hub, would enable earlier commissioning of planned projects and unlock additional capacity before 2031.
Streamlining permitting and grid connection procedures: Simplifying administrative processes, improving coordination across regions and accelerating grid connections would support faster deployment of utility-scale solar PV and onshore wind.
Solar PV and corporate PPAs drive renewable growth as Denmark redesigns offshore wind auctions
How much renewable electricity capacity is Denmark forecast to add by 2031?
- Denmark is forecast to add almost 8 GW of renewable capacity over 2026–2031, 15% more than during 2019–2025.
- Annual renewable capacity additions reached 1.6 GW in 2025, 80% above the 2024 level, and are expected to average 1.3 GW over 2026–2031.
- Solar PV is set to provide 76% of renewable capacity additions over 2026–2031, followed by offshore wind at 13% and onshore wind at 8%.
Has the IEA revised its renewable electricity forecast for Denmark compared to last year?
Summary: Denmark’s renewable capacity forecast is broadly unchanged from last year. An 8% downward revision for solar PV is offset by higher forecasts for bioenergy and onshore wind.
What is driving renewable capacity growth in Denmark?
Targets: Denmark aims to reach 33.1 GW of renewable capacity by 2030, including 17.8 GW of solar PV, 5.7 GW of onshore wind and 7.7 GW of offshore wind.
Corporate PPAs: Outside offshore wind, growth is increasingly driven by corporate PPAs, which provide developers with revenue certainty while helping companies meet decarbonisation targets. No dedicated auctions or other support mechanisms are currently planned.
Repowering: Onshore wind growth will be led by upgrades to existing projects, reflecting an ageing fleet, limited space for new sites and local opposition. Repowering is expected to account for around 90% of gross additions, while net capacity increases by only 0.6 GW. More efficient turbines will nonetheless raise output and capacity factors.
What are the main challenges to renewable capacity growth in Denmark?
Offshore wind auction design: In 2024, the Danish Energy Agency launched a 6 GW tender for six offshore wind sites in two rounds. The first round received no bids and the second was subsequently cancelled, prompting consultations and studies on a revised framework. Denmark now plans to re-tender 2.8 GW across three sites in 2026 and 2028 through 20-year capability-based two-sided CfDs, with more flexible deadlines and lower penalties to improve investor interest.
What would it take for Denmark to achieve the IEA accelerated forecast?
In the accelerated case, Denmark’s renewable capacity could be 26% higher than in the main case, with most of the upside from utility-scale solar PV and offshore wind.
Grid expansion and congestion: Faster transmission upgrades and stronger grid connections would be needed to accommodate additional offshore wind and solar PV capacity.
System flexibility and balancing: Higher shares of variable wind and solar would require additional storage, demand response, flexible generation and improved grid management.
Public acceptance and land use: Faster deployment would also depend on addressing community concerns, environmental impacts and constraints on suitable land for new wind and solar projects.
Finland remains on track for its 2030 renewable target despite a weaker onshore wind outlook
How much renewable electricity capacity is Finland forecast to add by 2031?
- Finland is forecast to add more than 9 GW of renewable capacity over 2026–2031, 10% less than over 2020–2025.
- Annual renewable capacity additions reached around 1.4 GW in 2025, 22% lower than in 2024. Over 2026–2031, annual additions are expected to average around 1.5 GW.
- Solar PV is set to account for more than half (53%) of renewable capacity additions over 2026–2031, followed by onshore wind (45%). Bioenergy and hydropower account for the remaining 2%.
Has the IEA revised its renewable electricity forecast for Finland compared to last year?
Summary: Finland’s renewable capacity forecast is revised down by around 17% from last year’s edition, mainly due to a lower onshore wind forecast (−33%). The solar PV and bioenergy forecasts remain broadly unchanged, while hydropower is revised up (+67%) but remains marginal in absolute terms.
Solar PV: The forecast remains broadly unchanged, but growth shifts from distributed to utility-scale projects. Utility-scale solar PV is revised up on a stronger project pipeline, improving permitting procedures, potential demand growth from data centres and hydrogen projects, and support for several projects from the EU Renewable Energy Financing Mechanism (RENEWFM). Distributed PV is revised down in both the commercial and residential segments, although the commercial segment remains larger in absolute terms, supported by corporate decarbonisation efforts.
Onshore wind: The forecast is revised down by around 33% on a weaker near-term construction pipeline and delays in project realisation. Around 1 GW is under construction, while around 3.7 GW of fully permitted projects and a development pipeline of more than 40 GW support the medium-term outlook.
Others: Hydropower is revised up, but its contribution to renewable capacity additions remains marginal. Bioenergy additions also remain limited. No offshore wind additions are expected by 2031, although the offshore wind policy framework is advancing.
What is driving renewable capacity growth in Finland?
Target: Finland’s updated national energy and climate plan (NECP) implies around 23 GW of renewable electricity capacity by 2030, within a broader national target for renewables to reach at least 62% of total final energy consumption.
Corporate PPAs and electricity demand: In the absence of auctions or other long-term revenue support schemes, corporate PPAs and merchant revenues remain central to project bankability. Rising demand from data centres, hydrogen projects and wider electrification strengthens the long-term case for new wind and solar PV capacity.
RENEWFM-backed utility-scale solar PV: The first two EU Renewable Energy Financing Mechanism (RENEWFM) tender rounds awarded funding to 13 solar PV projects totalling over 500 MW. A third round was launched in 2026.
Permitting reforms: Continued implementation of the revised EU Renewable Energy Directive (RED III), including renewable acceleration areas and shorter permitting timelines, supports the solar PV and onshore wind outlook.
What are the main challenges to renewable capacity growth in Finland?
Grid and transmission constraints: Grid connection constraints are becoming more significant in regions with high concentrations of wind and solar PV projects. Curtailment is not yet a major challenge but remains a forecast uncertainty if grid expansion does not keep pace with new capacity.
Permitting and regulation: The proposed Land Use Act reform creates uncertainty for onshore wind, as the suggested fixed minimum distance of 1.25 km from residential areas could significantly limit project siting.
Revenue risk: In the absence of government-backed contracts for difference or similar revenue-stabilisation mechanisms, the key uncertainty is whether permitted wind and solar PV projects can secure bankable corporate PPAs or sufficient merchant revenues to reach final investment decision. Corporate PPA demand depends mainly on electricity demand growth from data centres and hydrogen projects, the pace and scale of which remain uncertain.
Offshore wind development timelines: Finland has established a framework for offshore wind development in its exclusive economic zone and is preparing competitive tenders. However, lengthy permitting, grid-connection, financing and construction timelines make commissioning before 2031 unlikely. The main case also assumes that the more advanced Tahkoluoto Extension project is not commissioned by 2031.
What would it take for Finland to achieve the IEA accelerated forecast?
In the accelerated case, Finland’s renewable capacity additions could be around 42% higher than in the main case. The largest upside would come from solar PV, followed by onshore and offshore wind, while bioenergy and hydropower offer limited upside.
Stronger demand growth: Faster electrification, data centre investment and hydrogen project development would strengthen the market outlook for unsubsidised renewables and corporate PPA demand, helping more permitted wind and solar PV projects reach financial close and commissioning.
Effective permitting implementation: Faster implementation of RED III measures, including renewable acceleration areas and one-stop-shop permitting, would shorten development timelines.
Faster grid connection: Timely transmission reinforcements and shorter connection timelines would ease bottlenecks in high-resource regions and allow more advanced wind and solar PV projects to come online within the forecast period.
Timely delivery of the Tahkoluoto Extension project: Unlike the main case, the accelerated case assumes that the 600 MW project is commissioned in 2030–2031, requiring development and construction to proceed without significant delays.
France remains on track for its 2030 renewable power ambition despite a downward forecast revision
How much renewable electricity capacity is France forecast to add by 2031?
- France is forecast to add over 38 GW of renewable capacity over 2026–2031, 7% more than over 2020–2025.
- Annual renewable capacity additions reached a record 9.6 GW in 2025, 30% higher than in 2024. Over 2026–2031, annual additions are expected to average 6.4 GW, around one-third below the 2025 record.
- Solar PV is set to account for around 71% of renewable capacity additions over 2026–2031, followed by wind (28%). Bioenergy, hydropower, ocean energy and geothermal account for the remaining 1%.
Has the IEA revised its renewable electricity forecast for France compared to last year?
Summary: France’s renewable capacity forecast is revised down by 6% from last year’s edition, as downward revisions for onshore wind (−14%), offshore wind (−8%) and solar PV (−4%) outweigh upward revisions for bioenergy (+23%) and hydropower (+21%).
Distributed solar PV: The downward revision for solar PV is mainly driven by distributed PV, revised down by almost 19%. The June 2026 tariff order sharply reduced remuneration for installations up to 100 kW and shifted the business case further towards self-consumption. Support for new installations was simplified and reduced into a single purchase tariff of EUR 11/MWh for surplus electricity injected into the grid, and investment grants were abolished, significantly weakening the economics of small-scale systems, particularly those with low self-consumption rates. Lower retail electricity prices since early 2025 further reduce the attractiveness of residential solar PV. In addition, the first simplified auction for 100–500 kW projects in October 2025 was undersubscribed, awarding around 44 MW of the 192 MW on offer.
Utility-scale solar PV: The forecast is revised up by around 14%, partly offsetting the downward revision for distributed PV. This reflects strong recent deployment, a sizeable pipeline of awarded projects, continued auction oversubscription and improved visibility over future auction rounds and volumes under France’s multiannual energy plan (PPE3), published in February 2026.
Onshore wind: The forecast is revised down by 14% on weaker recent deployment and longer project realisation timelines due to permitting, legal and grid connection delays. Additions are nevertheless expected to recover as auction-awarded projects are commissioned.
Offshore wind: The forecast is revised down due to delays in the realisation of awarded projects. PPE3 provides greater visibility for future offshore procurement, but long development timelines and grid connection and commissioning risks mean that most capacity from upcoming tenders is unlikely to come online before 2031.
What is driving renewable capacity growth in France?
Targets: PPE3 sets technology-specific ambitions implying around 112 GW of renewable electricity capacity by 2030, with solar PV and onshore wind accounting for more than two-thirds of the total. Its finalisation also provides clearer visibility over future auction volumes, supporting investment decisions.
Auction schemes: Competitive tenders remain the main driver for utility-scale solar PV, onshore and offshore wind, and part of the commercial solar PV segment.
Self-consumption: Following the latest purchase tariff cuts, distributed solar PV growth is increasingly driven by self-consumption, with limited revenue certainty through surplus-generation tariffs.
Corporate PPAs: Corporate PPAs offer a growing complementary route to market for solar PV and onshore wind. Interest from large electricity consumers is increasing, but the PPA market remains small and public support schemes continue to dominate project development.
What are the main challenges to renewable capacity growth in France?
Permitting and local acceptance: Lengthy permitting procedures, legal appeals and local opposition continue to slow onshore wind and, to a lesser extent, utility-scale solar PV, extending development timelines and reducing realisation rates for awarded projects. The 2023 law on accelerating renewable energy production (APER) aims to speed up permitting through renewable acceleration zones and simplified procedures, but its impact on lead times remains uncertain, particularly for onshore wind.
Support scheme changes: Lower purchase tariffs have made distributed solar PV economics increasingly dependent on self-consumption and are expected to slow distributed PV additions from 2026, following rapid growth in 2024–2025.
Grid connection: Connection queues and local network constraints remain important bottlenecks for distributed and utility-scale solar PV and onshore wind. For offshore wind, the key challenge is timely coordination of offshore transmission with project development.
Electrification pace: If electricity demand from transport, buildings and industry grows more slowly than planned, integrating additional renewable generation alongside the existing nuclear fleet could become more challenging, increasing periods of surplus output and low prices.
Policy implementation: PPE3 improves policy visibility, but its impact will depend on translating targets and planned volumes into timely auctions.
Offshore wind delivery: Long development timelines, permitting steps, and grid connection and commissioning risks limit the offshore wind contribution before 2031.
What would it take for France to achieve the IEA accelerated forecast?
In the accelerated case, France’s renewable capacity additions could be 22% higher than in the main case. The largest upside would come from solar PV, followed by onshore and offshore wind, with smaller additional gains from ocean energy, bioenergy, geothermal and hydropower.
Faster solar PV and onshore wind realisation: Sustaining recent momentum would require faster implementation of renewable acceleration zones, stable auction volumes, higher auction participation, faster grid connection, and shorter approval timelines with fewer legal delays, supported by greater social acceptance.
Timely offshore wind delivery: Faster commissioning of awarded projects through shorter permitting timelines and timely grid connection would increase offshore wind additions.
Grid, battery storage and flexibility expansion: Grid reinforcement, improved connection procedures, faster battery storage deployment and greater demand-side flexibility would support higher solar PV and wind integration, especially in regions with growing congestion.
Utility-scale solar PV and onshore wind drive Germany's capacity expansion, while offshore wind and distributed PV growth is slowing down
How much renewable electricity capacity is Germany forecast to add by 2031?
- Germany is forecast to add almost 171 GW of renewable capacity over 2026-2031, nearly double the 86 GW added over 2020-2025.
- Annual renewable capacity additions reached a record 22.7 GW in 2025, 10% above 2024. Over 2026-2031, additions are expected to average almost 30 GW per year.
- Solar PV accounts for over 60% of renewable capacity additions over 2026-2031 (utility-scale 43%, distributed around 20%) and wind for 36% (onshore 29%, offshore 7%). Hydropower and bioenergy each contribute less than 1%.
Has the IEA revised its renewable electricity forecast for Germany compared to last year?
Summary: Germany's renewable capacity forecast is revised down slightly (-4%) from last year's edition, as the downward revisions for distributed solar PV (-22%) and offshore wind (-19%) offset the upward revision for utility-scale PV (+9%). Onshore wind is broadly unchanged (-1%).
Onshore wind: The onshore wind forecast is broadly unchanged, as positive auction developments are offset by lower project realisation and policy uncertainty. Permitting reforms have supported nine consecutive oversubscribed auctions since August 2024, with stronger competition reducing awarded prices from around EUR 73/MWh to below EUR 50/MWh. The forecast therefore raises assumed auction subscription from 92% to 100% and includes additional volumes proposed under the draft EEG 2027. However, an estimated realisation rate of 88% largely offsets this upside. Proposed capacity-density limits, negative-price provisions and uncompensated curtailment under the draft EEG 2027 and Grid Package could weaken project economics, depending on the final legislation.
Utility-scale solar PV: Utility-scale solar PV is revised up, driven by the draft EEG 2027 proposal to raise annual ground-mounted solar PV auction volumes from 9.9 GW to 14 GW over 2027-2032 and by stronger-than-expected corporate PPA-backed deployment in 2025 and the first half of 2026. Oversubscribed innovation auctions, dominated by solar-plus-storage projects, provide further support.
Distributed solar PV: Distributed PV is revised down, reflecting year-on-year declines of 20% in commercial and 10% in residential PV additions in the first half of 2026. The draft EEG 2027 would further tighten support, including eliminating feed-in tariffs, removing support for systems below 25 kW (with temporary transition measures), limiting grid exports from certain smaller systems and reducing rooftop auction volumes from 2.3 GW to 1.5 GW per year. These proposals reflect the expectation that distributed PV combined with batteries is increasingly economically attractive without direct support.
Offshore wind: Offshore wind is revised down following the August 2025 auction, which received no bids, and the postponement of the 2026 rounds to 2027 to allow the auction framework to be redesigned. The government has signalled a shift towards two-sided CfDs, while grid connection availability and construction timelines further constrain deployment.
Biomass: Biomass is revised down after only about 1.5 GW was awarded of the roughly 1.9 GW offered in biomass and biomethane auctions between February 2025 and September 2026, mainly because the April 2026 biomass round and all biomethane rounds were undersubscribed. The draft EEG 2027 is not reflected in the biomass forecast as it is not yet final, but offers upside potential: it would raise biomass auction volumes to 1 GW a year in 2027-2028, retain a one-sided market premium for biomass and abolish biomethane auctions. Whether this attracts sufficient developer interest remains uncertain.
What is driving renewable capacity growth in Germany?
Target: The EEG 2023 sets a target for renewables to supply 80% of gross electricity consumption by 2030, reaffirmed in the 2026 Climate Protection Programme and the draft EEG 2027. Technology-specific targets include 115 GW of onshore wind, 215 GW of solar PV and 30 GW of offshore wind by 2030.
Auction schemes: Competitive auctions are the main support mechanism for utility-scale renewables. The draft EEG 2027 proposes moving from one-sided feed-in premiums to two-sided CfDs with annual settlement over 20 years. Compared with the current EEG, it would increase onshore wind auction volumes by 12 – 15 GW to 2030, raise annual ground-mounted solar PV volumes from 10 GW to 14 GW and reduce rooftop PV volumes from 2.5 GW to 1.5 GW. It also earmarks part of the wind and solar PV auction volumes for “resilience auctions” targeting projects that support system integration, such as hybrid solar-wind and/or battery projects. Biomass auction volumes are raised and biomass is exempt from the CfD transition, while biomethane auctions are discontinued.
Permitting reforms: Reforms introduced since 2022, including classifying wind projects as being of overriding public interest, resulted in record onshore wind permitting volumes in 2025. The resulting expansion of the ready-to-bid projects has supported oversubscribed auctions and declining award prices, strengthening near-term deployment.
Corporate PPAs and demand pull: Corporate PPAs emerging as a potential route to market outside auctions, particularly for utility-scale solar PV. Rising electricity demand from industrial electrification and data centres supports their growth.
Storage integration: Proposed changes in the draft EEG 2027 that increase exposure to negative-price periods strengthen incentives for co-located batteries and flexible operation. By shifting output away from low- and negative-price periods, co-located storage could improve capture prices and project economics for solar PV and onshore wind.
What are the main challenges to renewable capacity growth in Germany?
Draft EEG 2027 uncertainty: Several elements of the draft EEG 2027 remain under discussion, notably the shift from fixed feed-in tariffs to market-based remuneration for small PV systems, new limits on grid exports from distributed PV and remuneration rules for CfDs. Their final form and timing are a key forecast uncertainty, particularly for distributed PV.
Draft Grid Package uncertainty: The draft Grid Package aims to better align renewable deployment with grid capacity. Proposed reductions in curtailment compensation in congested grid areas and new limits on grid feed-in for utility-scale plants could affect project economics, and their final design remains a key forecast uncertainty.
Offshore wind framework redesign: The August 2025 tender, which received no bids, and the postponement of the 2026 tenders to 2027 reflect a weaker business case under the current zero-subsidy model. A bankable auction framework, potentially based on indexed two-sided CfDs, together with timely delivery of offshore grid connections and substation equipment, will be critical to restoring developer confidence.
Grid connection and network availability: Delays in offshore grid connection infrastructure are pushing commissioning beyond original schedules, increasing the risk that the 30 GW offshore wind target for 2030 is missed.
Curtailment and negative prices: Rising solar PV and wind shares are increasing curtailment and the number of negative-price hours. The Solar Peak Act (2025) already suspends support during negative-price periods, and the proposed Grid Package could also require new projects in designated grid-constrained areas to accept reduced curtailment compensation, increasing revenue and financing risks. Further growth of variable renewables will require faster deployment of battery storage and other flexibility resources to safeguard project economics.
Distributed PV slowdown: Weaker economics for small commercial and residential systems and the phased removal of remuneration under the draft EEG 2027 weigh on distributed PV growth. The pace of the shift to PV-plus-battery systems remains a forecast uncertainty.
What would it take for Germany to achieve the IEA accelerated forecast?
In the accelerated case, Germany's renewable capacity additions could be 23% higher than in the main case. The largest upside would come from onshore wind and utility-scale solar PV, followed by offshore wind and distributed PV.
Timely finalisation of the EEG 2027 and Grid Package: Rapid adoption of the final EEG 2027, and stable auction schedules to 2032, would improve investor certainty and support a larger project pipeline.
Restoring offshore wind bankability: Timely introduction of two-sided CfDs for offshore wind from 2027, together with faster grid connection commissioning and offshore grid coordination, would enable earlier delivery of awarded projects and unlock additional capacity before 2031.
Faster battery storage and flexibility deployment: Faster deployment of battery storage, more hybrid solar-plus-storage and wind-plus-storage projects, and greater demand-side flexibility would reduce curtailment and improve capture prices, strengthening project economics for both utility-scale and distributed renewables.
Sustained permitting progress and repowering: Continued permitting progress and stronger incentives to repower ageing onshore wind sites would sustain net additions and offset retirements of end-of-life turbines.
Strong solar PV and wind pipelines support Greece’s renewable growth, while curtailment and grid constraints limit further expansion
How much renewable electricity capacity is Greece forecast to add by 2031?
- Greece is forecast to add almost 13 GW of renewable capacity over 2026–2031, 20% more than during 2020–2025.
- Annual renewable capacity additions reached 2.2 GW in 2025, 11% below the 2024 level, and are expected to average around 2.1 GW over 2026–2031.
- Solar PV is set to provide 74% of renewable capacity additions over 2026–2031, followed by wind at 19% and hydropower at 7%, while bioenergy contributes less than 1%.
Has the IEA revised its renewable electricity forecast for Greece compared to last year?
Summary: Greece’s renewable capacity forecast is 33% higher than last year, led by upward revisions for onshore wind (+57%) and solar PV (+33%). Bioenergy doubles from a small base, while hydropower is unchanged.
Solar PV: The forecast is revised up from 6.3 GW to 8.4 GW over 2026–2030, reflecting strong 2025 additions, around 800 MW of completed projects awaiting grid connection and a large pipeline due online in 2026–2027. After 2027, rising curtailment, lower capture prices and grid bottlenecks constrain growth.
Onshore wind: The forecast is revised up from 1.3 GW to 2.1 GW over 2026–2030, reflecting a larger pipeline of awarded projects under development. However, licensing and grid-connection delays continue to slow commissioning and limit further upside.
What is driving renewable capacity growth in Greece?
Target: Greece’s updated NECP sets an ambition of more than 28 GW of renewable capacity by 2030.
Near-term project pipeline: Solar PV deployment remains strong, with around 1.8 GW connected in 2025 and 0.8 GW of completed capacity awaiting grid connection. Onshore wind is supported by more than 1 GW of projects under construction or development at end-2025.
Policy support and permitting reforms: Greece has introduced net billing and virtual net billing for self-consumption, launched the Apollo auction programme, which selected around 0.3 GW of onshore wind, and transposed elements of RED III through Law 5299/2026. The law establishes renewable acceleration areas and shorter licensing procedures.
Merchant projects and corporate PPAs: Merchant projects support growth, particularly for larger solar PV plants, while corporate PPAs remain a potential but underdeveloped route to market.
What are the main challenges to renewable capacity growth in Greece?
Grid constraints and curtailment: Grid congestion and rising curtailment are becoming major constraints, particularly as solar output increasingly exceeds the grid’s absorption capacity. These pressures weaken the outlook for PV-only projects without storage.
Market revenues and bankability: Zero and negative-price hours, declining capture prices and balancing costs are raising revenue risks, especially for solar PV. Although the corporate PPA market is expanding, its pace and scale remain uncertain.
Permitting and project execution: Onshore wind continues to face administrative, permitting and grid-connection delays. RED III implementation could shorten timelines, but is more likely to support additions from 2029 onwards.
Auction outcomes: The Apollo wind auction supports the near-term onshore wind outlook, while the unsuccessful solar-plus-storage tender limits storage-backed PV deployment.
What would it take for Greece to achieve the IEA accelerated forecast?
In the accelerated case, Greece’s renewable capacity additions could be around 30% higher than in the main case, with most upside from solar PV and onshore wind. Pumped storage hydropower, bioenergy and geothermal offer only limited additional potential.
Lower curtailment and faster storage deployment: Faster battery commissioning and grid upgrades would reduce curtailment and strengthen solar PV project revenues.
Faster grid connection: Shorter connection timelines would allow more permitted projects to commission within the forecast period.
Effective permitting improvements: Effective implementation of renewable acceleration areas and shorter RED III procedures would accelerate utility-scale solar PV and onshore wind projects.
Stronger revenue certainty: More bankable corporate PPAs and continued policy support would help projects reach final investment decisions despite curtailment and low-price hours.
FER X auctions put Italy’s 2030 renewable ambitions within reach as solar PV accelerates
How much renewable electricity capacity is Italy forecast to add by 2031?
- Italy is forecast to add 52 GW of renewable capacity over 2026–2031, twice as much as during 2019–2025.
- Annual renewable capacity additions reached 7 GW in 2025, around 5% above the 2024 level, and are expected to accelerate to 10 GW by 2031.
- Solar PV dominates the outlook, providing 90% of renewable capacity additions over 2026–2031, with onshore wind accounting for the remainder.
Has the IEA revised its renewable electricity forecast for Italy compared to last year?
Summary: Italy’s renewable capacity forecast is 5% higher than last year, although revisions vary by technology. Utility-scale solar PV is revised up by almost 50%, mainly reflecting higher-than-expected FER X auction awards. Distributed solar PV (-6%) and onshore wind (-47%) are revised down following a sharper installation slowdown and lower-than-expected auction volumes, respectively.
What is driving renewable capacity growth in Italy?
Target: Italy’s National Energy and Climate Plan aims for 131 GW of installed renewable electricity capacity by 2030, including 79 GW of solar PV and 28 GW of wind. The forecast puts the overall ambition within reach, although solar PV contributes more and wind less than envisaged.
Auctions: The first FER X auction in December 2025 awarded almost 9 GW of solar PV and more than 400 MW of onshore wind, a sharp increase from the repeatedly undersubscribed FER auctions held over 2019–2024. Higher tariff ceilings, remuneration during negative-price hours and 36-month commissioning deadlines strengthened participation. The scheme aims to support more than 37 GW of renewable additions and is a central growth driver over the forecast period.
Distributed PV: Distributed solar PV growth slowed after the Superbonus tax incentive ended, following record residential installations in 2023. However, high retail electricity prices, improving self-consumption economics and commercial and industrial demand continue to support deployment. As Italy shifts from Scambio sul Posto net metering towards market-based remuneration for exports, falling solar PV and battery costs support higher self-consumption. Renewable Energy Communities and collective self-consumption schemes provide further growth opportunities.
Corporate procurement: Corporate procurement is an increasingly important growth driver, supported by PPAs and the Energy Release 2.0 scheme. Energy-intensive companies receive fixed-price electricity through GSE in exchange for commitments to develop new renewable capacity directly or through third-party producers. Corporate procurement is expected to support around 20% of utility-scale solar PV and onshore wind growth over the forecast period.
What are the main challenges to renewable capacity growth in Italy?
Lengthy and complex permitting: Despite reforms to simplify procedures and expand eligible areas, long approval timelines, uneven regional implementation and social acceptance continue to delay onshore wind and utility-scale solar PV projects.
Transmission system capacity: Renewable resources are concentrated mainly in southern regions and islands, while demand is higher in northern industrial centres. Limited interregional transmission capacity and growing connection queues could delay projects, requiring faster network expansion and reinforcement.
VRE system integration: Rising solar PV and wind shares require faster deployment of storage, demand response and grid digitalisation. Although battery deployment is accelerating through capacity-market mechanisms and dedicated storage auctions, further flexibility is needed to reduce curtailment risks.
What would it take for Italy to achieve the IEA accelerated forecast?
In the accelerated case, Italy’s renewable capacity could be one-third higher than in the main case, with most upside from distributed solar PV, followed by utility-scale solar PV and onshore wind.
Streamlined permitting: Simpler administrative requirements, stronger coordination between authorities and greater digitalisation could shorten development timelines and accelerate solar PV and wind deployment.
Enhanced support for distributed PV: Better access to finance, stronger support for energy communities and collective self-consumption, and more attractive self-consumption economics could accelerate rooftop solar PV after the Superbonus phase-out.
Reduced grid connection queues: Faster transmission and distribution expansion, streamlined connection procedures and closer alignment between grid plans and project pipelines would enable greater wind and solar PV deployment.
Grid reform and offshore wind policy adjustments are needed to restore renewable growth in the Netherlands
How much renewable electricity capacity is the Netherlands forecast to add by 2031?
- The Netherlands is forecast to add around 17 GW of renewable capacity over 2026–2031, 44% less than during 2020–2025.
- Annual renewable capacity additions fell to 2.2 GW in 2025, 49% below the 2024 level, and are expected to average almost 3 GW over 2026–2031.
- Solar PV is set to provide 75% of renewable capacity additions over 2026–2031, with wind accounting for 25% and other technologies for less than 1%.
Has the IEA revised its renewable electricity forecast for the Netherlands compared to last year?
Summary: The Netherlands’ renewable capacity forecast is 30% lower than last year. Utility-scale solar PV (+44%) and onshore wind (+10%) are revised up, while distributed solar PV (-37%), offshore wind (-45%) and bioenergy (-2%) are revised down.
Solar PV and wind: Downward revisions reflect the sharp slowdown in 2025 amid grid congestion, evolving support schemes and weaker market conditions. However, permitted and financed utility-scale solar PV and onshore wind projects continue to support near-term additions.
What is driving renewable capacity growth in the Netherlands?
Target: The Netherlands aims for a CO2-free electricity sector by 2035. Supporting this goal, the Offshore Wind Energy Roadmap targets 23 GW of offshore wind capacity by 2032.
Renewable auctions and SDE++: The SDE++ programme remains the main support mechanism for utility scale renewable deployment, with EUR 8 billion budgeted for the 2026 round. In contrast, weaker project economics are weighing on offshore wind: the Nederwiek I-A tender received no applications in 2025 amid rising costs. Two-way CfDs are therefore set to be introduced from 2027.
New Energy Act: Effective from 2026, the act enables flexibility tools including non-firm connections, time-dependent transport rights, capacity sharing, group transport agreements and demand-side flexibility.
Distributed solar PV: High retail electricity prices and falling solar PV costs continue to support rooftop and commercial self-consumption, despite the end of net metering from January 2027. While growth is lower than previously expected, distributed solar PV additions are still forecast to increase during the forecast period.
What are the main challenges to renewable capacity growth in Netherlands?
Grid congestion: Grid congestion is the main constraint on renewable growth. The Energy Act and Aansluitoffensief package seek to improve use of existing infrastructure through flexible and non-firm connections, congestion management and capacity sharing. These measures can enable more solar PV, wind and storage projects, but cannot fully replace physical network expansion.
Permitting and spatial constraints: Renewable projects face tighter land constraints as many optimal sites have already been developed. Competition from housing, nature protection, agriculture and industry is lengthening permitting for utility-scale solar PV and onshore wind.
What would it take for the Netherlands to achieve the IEA accelerated forecast?
In the accelerated case, the Netherlands’ renewable capacity could be around 37% higher than in the main case, with most upside from solar PV, followed by onshore wind.
Grid reform: Effective implementation of the planned reform package could significantly shorten waiting times for existing and new grid connections.
Renewable acceleration areas: Timely RED III implementation and designation of acceleration areas could shorten permitting to 12 months for new projects and 6 months for repowering.
Electricity Projects Decree: The draft temporary framework, envisaged until 2032, could shorten planning and permitting for key electricity infrastructure, enabling further renewable growth.
Offshore wind commissioning and continued solar PV growth drive Poland’s renewable expansion
How much renewable electricity capacity is Poland forecast to add by 2031?
- Poland is forecast to add 34 GW of renewable capacity over 2026–2031, 20% more than during 2019–2025.
- Annual renewable capacity additions reached 4.2 GW in 2025, around 15% below the 2024 level, and are expected to average 5.7 GW over 2026–2031.
- Solar PV leads the outlook, providing 70% of renewable capacity additions over 2026–2031, followed by offshore wind at 17%, onshore wind at 9% and hydropower at 3%.
Has the IEA revised its renewable electricity forecast for Poland compared to last year?
Summary: Poland’s renewable capacity forecast is broadly unchanged from last year, although revisions vary by technology. Utility-scale solar PV is revised up by 24%, reflecting stronger deployment and higher-than-expected 2025 auction awards. This is offset by lower forecasts for distributed solar PV (-23%), following a sharper installation slowdown, and onshore wind (-8%), owing to continued turbine siting restrictions.
What is driving renewable capacity growth in Poland?
Target: Poland’s final NECP, adopted in June 2026, targets almost 57 GW of renewable electricity capacity and a 53% renewable share in electricity consumption by 2030. Planned capacity includes 32 GW of solar PV, 16 GW of onshore wind and 5.9 GW of offshore wind. The forecast exceeds the overall capacity ambition, as stronger solar PV growth more than offsets slower onshore wind expansion.
Auctions: Competitive auctions remain Poland’s main support mechanism for utility-scale solar PV and onshore wind. Since 2016, almost 11 GW of solar PV and 5.5 GW of onshore wind have been awarded. The record 1.7 GW of solar PV awarded in 2025 supports the upward forecast revision, while only 0.2 GW of onshore wind has been awarded since 2023 amid continued turbine siting restrictions.
Distributed PV: Distributed solar PV additions fell to 1.1 GW in 2025 from a record 3.2 GW in 2022, when net metering and the Mój Prąd programme supported growth. Lower subsidies and the shift to net billing have weakened project economics. Nevertheless, high retail prices, continued investment support and falling battery costs are expected to sustain average additions of around 1.3 GW per year over the forecast period.
Offshore wind: Poland’s offshore wind programme is entering the commissioning phase, with the first 0.6 GW expected online in 2026 and cumulative capacity reaching almost 6 GW by 2031. A December 2025 auction awarded 3.4 GW for the second development phase, with commissioning expected after 2031.
What are the main challenges to renewable capacity growth in Poland?
Turbine siting restrictions and permitting: Minimum-distance rules were relaxed in 2023 from ten times turbine height to 700 metres, but further reform has stalled amid limited political consensus. Current restrictions continue to constrain available sites, while complex procedures, limited digitalisation and the absence of a centralised permitting framework lengthen development timelines.
Transmission system capacity: Grid connection availability remains a key constraint. In 2025, system operators rejected requests covering 107 GW of generation and consumption capacity, 45% more than in 2024. Reforms introduced in May 2026 aim to streamline procedures, improve capacity allocation and reduce speculative projects, but continued network expansion remains essential.
VRE system integration: Rising solar PV and wind generation requires more storage, demand response and grid capacity. Renewable electricity curtailment almost doubled to around 1.4 TWh in 2025.
What would it take for Poland to achieve the IEA accelerated forecast?
In the accelerated case, Poland’s renewable capacity could be almost 30% higher than in the main case, with most upside from distributed solar PV, followed by onshore wind and utility-scale solar PV.
Enhanced distributed PV support: Stronger self-consumption incentives, faster development of energy communities and broader support for commercial and industrial consumers could unlock additional distributed solar PV growth.
Streamlined permitting: Simpler requirements, stronger coordination between authorities and greater digitalisation could shorten development timelines for solar PV and wind.
Relaxed turbine siting rules: Further easing distance restrictions would expand available development areas, strengthen the project pipeline and increase participation in future auctions.
Higher grid and flexibility investment: Faster transmission and distribution expansion, shorter connection delays, and more batteries and demand response would enable higher solar PV and wind integration.
CfD auctions and support schemes drive record renewable growth, but sustaining momentum depends on grid expansion and effective reform implementation
How much renewable electricity capacity is Romania forecast to add by 2031?
- Romania is forecast to add more than 13 GW of renewable capacity over 2026–2031, more than twice the additions during 2020–2025.
- Annual renewable capacity additions reached around 2.6 GW in 2025, 55% above the 2024 level, and are expected to average above 2 GW over 2026–2031.
- Solar PV is set to provide 72% of renewable capacity additions over 2026–2031, followed by wind at 27%, while hydropower and bioenergy together account for the remaining 1%.
Has the IEA revised its renewable electricity forecast for Romania compared to last year?
Summary: Romania’s renewable capacity forecast is broadly unchanged compared to last year, with solar PV revised up by 11%. This almost offsets lower forecasts for hydropower (-59%) and wind (-18%).
Solar PV: The outlook is stronger than last year, supported by faster-than-expected distributed and commercial PV deployment as project economics improve.
Wind and hydropower: The onshore wind forecast is revised down due to weaker near-term project delivery and higher transmission and integration risks. Hydropower is revised down sharply because delayed pumped-storage projects are unlikely to commission within the forecast period.
What is driving renewable capacity growth in Romania?
Target: Romania’s updated NECP targets a 38.3% renewable share in gross final consumption by 2030 and projects 57.8 % renewables share in the electricity sector. The plan foresees 8.2 GW of solar PV and 7.3 GW of onshore wind capacity by 2030.
CfD auctions: Two-sided CfDs are the main driver of utility-scale deployment. Romania’s first two auctions awarded 4.2 GW, including 2.75 GW in the second round, exceeding the 3.5 GW Recovery and Resilience Plan target. Long-term revenue certainty has attracted strong developer interest, while a third wind-only round signals continued policy commitment.
Distributed solar PV economics: High retail electricity prices, falling technology costs and self-consumption incentives continue to support distributed PV. Although support has shifted from standalone rooftop systems towards PV paired with batteries, as project economics continue to improve.
Grid reform: Revised connection rules aim to prioritise mature projects through tighter documentation, deadlines and financial guarantees, gradually improving pipeline credibility and freeing capacity in congested queues.
What are the main challenges to renewable capacity growth in Romania?
Grid constraints and near-term delivery: Despite stronger visibility from CfD procurement, grid connection constraints, longer lead times and higher investment risks continue to delay utility-scale projects, particularly wind. Delayed pumped-storage projects also limit dispatchable renewable capacity within the forecast period, increasing integration challenges for further solar PV and wind growth.
Permitting and implementation risk: Despite significant policy improvements, the regulatory framework remains complex. Permitting, licensing and grid-access reforms require clear implementing rules and consistent interpretation to reduce investor uncertainty and accelerate delivery.
What would it take for Romania to achieve the IEA accelerated forecast?
In the accelerated case, Romania’s renewable capacity could be around 29% higher than in the main case, with most upside from wind, followed by hydropower and solar PV.
Additional auctions and continued CfD visibility: Faster deployment would require continued CfD procurement with clear volumes and timelines, building on recent auction momentum.
More flexibility and storage: Faster battery and flexibility deployment would reduce integration risks and improve variable renewable economics. Earlier financial close and construction of delayed hydropower projects would provide further upside.
Successful auctions support Serbia’s renewable growth, but the grid-connection freeze constrains deployment until 2029
How much renewable electricity capacity is Serbia forecast to add by 2031?
- Serbia is forecast to add almost 2 GW of renewable capacity over 2026–2031, 64% more than during 2020–2025.
- Annual renewable capacity additions reached around 0.6 GW in 2025, almost three times the 2024 level, and are expected to average around 0.3 GW over 2026–2031.
- Solar PV is set to provide 68% of renewable capacity additions over 2026–2031, followed by wind at 30%, while hydropower accounts for the remaining 2%.
Has the IEA revised its renewable electricity forecast for Serbia compared to last year?
Summary: Serbia’s renewable capacity forecast is 25% lower than last year, with downward revisions across technologies, including solar PV (-23%) and wind (-30%).
Solar PV and wind: The downward revision mainly reflects the May 2026 decision to postpone many new transmission-level connection studies for variable renewables until September - December 2029, delaying much of the utility-scale solar PV and wind pipeline without secured grid status.
What is driving renewable capacity growth in Serbia?
Target: Serbia’s integrated national energy and climate plan, adopted in July 2024, targets around 45% share of renewable energy in gross final electricity consumption from renewables by 2030.
Auctions: Competitive auctions offering 15-year CfD-style support or market premiums remain the main driver of utility-scale deployment. Following the successful 2023 round, the February 2025 auction awarded 645 MW of wind and solar PV projects amid strong oversubscription and competitive prices.
Market integration and industrial demand: Serbia has completed the regulatory requirements for electricity-market coupling with the European Union, which should improve trading efficiency and market integration.
What are the main challenges to renewable capacity growth in Serbia?
Grid connection moratorium: The postponement of many new grid-connection studies for variable renewable projects until late 2029 is the main near-term constraint, effectively stalling further large-scale project development.
Financial and execution pressure: The May 2026 amendments to the Regulation on Conditions for Electricity Delivery and Supply tightened financial requirements for connection studies and guarantees, increasing early-stage development risk. Large strategic renewable and storage projects also face financing, land-use and execution challenges.
What would it take for Serbia to achieve the IEA accelerated forecast?
In the accelerated case, Serbia’s renewable capacity additions could almost double compared to the main case, with most upside from hydropower, followed by solar PV and wind.
Earlier grid relief and faster network upgrades: The accelerated case requires grid-connection bottlenecks to ease before December 2029, alongside faster transmission reinforcement and more effective queue management so more existing wind and solar projects can reach construction.
Timely flexibility investment: Faster progress on pumped-storage hydropower, particularly the PSHPP Bistrica project, would strengthen system flexibility and support higher solar PV and wind deployment.
Continued auction visibility: Timely delivery of the next auction and a visible procurement pipeline would strengthen developer confidence and support faster capacity growth later in the forecast period.
Spain remains a leader in market-based renewable deployment as storage and flexibility become the next growth frontier
How much renewable electricity capacity is Spain forecast to add by 2031?
- Spain added a record 15.2 GW of renewable capacity in 2025, 15% more than in 2024. Growth was driven by projects backed by merchant revenues and corporate power purchase agreements (PPAs), reflecting the maturity of Spain's renewables market. Over 2026-2031, additions are expected to average around 7 GW per year, raising cumulative renewable capacity by 35% to almost 160 GW.
- Solar PV is set to account for almost 85% of Spain's renewable capacity additions over 2026-2031, with utility-scale projects contributing 61% and distributed PV 24%. Onshore wind accounts for 11%, hydropower (mainly pumped storage) 3% and bioenergy the remainder.
Has the IEA revised its renewable electricity forecast for Spain compared with last year?
Summary: Spain remains the global leader in unsubsidised solar PV and wind capacity growth. However, more frequent negative electricity prices and rising curtailment are weighing on project economics, and the renewable capacity forecast is revised down by 17% from last year's edition, with diverging trends across technologies.
Onshore wind: The onshore wind forecast is revised down because of a shrinking project pipeline and much slower-than-expected growth in 2025 and the first half of 2026. Only around 4 GW of new projects have secured financing, of which just 2.6 GW are backed by long-term (>10-year) corporate PPAs. Project economics are weakening as hours with negative prices become more frequent, curtailment risk rises and utility-scale solar PV paired with battery storage increasingly competes in the evening hours, when wind has traditionally earned higher prices. Permitting delays, social acceptance challenges and long development lead times add further pressure. Reforms introduced in 2026 could improve project delivery: they aim to reduce permitting delays and legal challenges by requiring earlier engagement with local authorities and landowners, strengthening community benefit-sharing and prioritising projects that deliver local and environmental benefits. The pace of repowering Spain's ageing fleet remains a further uncertainty, although two funding rounds under the REPOTEN programme have supported more than 100 projects since 2023.
Utility-scale solar PV: The utility-scale solar PV forecast is revised up modestly following stronger-than-expected additions of around 12 GW in 2025. The revision also reflects expected improvements in system flexibility, supported by new regulations facilitating storage deployment, a technology-neutral support programme of more than EUR 800 million for stand-alone storage, and greater co-location of PV with storage, which should raise capture prices for new projects. However, additions from January to August 2026 were 25% lower year-on-year, and the 15-21 GW pipeline of late-stage projects is gradually shrinking in the absence of new auction rounds.
Distributed solar PV: The distributed solar PV forecast is revised down. While the forecast for residential applications remains unchanged, commercial PV is revised down following slower-than-expected growth in 2025, as the economics of larger self-consumption systems weakened.
Other technologies: Pumped storage hydropower is revised down due to project development delays and slower construction progress than previously assumed. Despite long construction timelines, the project pipeline is expanding, supported by government funding rounds that have awarded EUR 265 million to 11 projects. Bioenergy is also revised down from a small base, reflecting limited new project activity.
What is driving renewable capacity growth in Spain?
Target: Spain's updated National Energy and Climate Plan (NECP) targets a 48% renewable share in final energy consumption and 81% in the electricity mix by 2030. These goals are underpinned by 76 GW of solar PV, 62 GW of wind, 22.5 GW of storage and 19 GW of self-consumption capacity.
Merchant and corporate PPA-driven deployment: No new competitive auctions have been held since 2022, so all utility-scale solar PV and wind additions expected over the forecast period are backed by corporate PPAs, merchant revenues or a combination of both. A mature pipeline of projects with permitting and grid-connection approvals underpins Spain's position as a global leader in unsubsidised variable renewable deployment.
Storage policies enabling hybrid projects: The government is accelerating short- and long-duration storage deployment through dedicated 2030 targets and a grant programme of more than EUR 800 million for stand-alone battery energy storage systems (BESS), thermal storage and pumped storage. Several projects have also been approved as EU Projects of Common Interest. The battery storage pipeline is strong, with around 34 GW of projects already granted grid access. Recent regulatory changes recognise storage as a system flexibility resource and enable hybrid PV-plus-storage configurations, which should support higher capture prices for new solar PV projects.
Strategic grid access: Grid tenders introduced in 2024 allocate network capacity to strategic projects, prioritising industrial electrification and renewable-based hydrogen. Between April 2024 and May 2025, more than 21 GW of grid connections were requested across key transmission lines, creating additional demand for utility-scale renewables. In addition, Spain's 2026 grid reform aims to increase network investment and introduces anticipatory planning, allowing future demand to connect earlier and supporting electrification.
Self-consumption and rooftop momentum: Distributed solar PV growth is supported by a favourable regulatory framework, strong self-consumption economics and declining battery costs. Distributed generation is also increasingly valued for its contribution to system resilience and security of supply.
What are the main challenges to renewable capacity growth in Spain?
Rising negative prices and curtailment: Zero and negative prices are becoming more frequent during hours of high solar PV generation, reducing capture prices for merchant projects. Greater intraday price volatility is raising the value of storage, but storage and flexibility deployment is not keeping pace with solar PV additions. This increases curtailment risk and weakens the business case for further unsubsidised deployment. The capacity market, formally established in September 2026, could strengthen investment signals for storage and other flexibility technologies needed to integrate rising renewable generation.
Absence of new auction rounds: Spain is redesigning its utility-scale auction framework to address developer challenges, but uncertainty over the volume and timing of future rounds limits investment visibility. Project bankability currently depends largely on corporate PPAs and merchant revenues, both of which are weakening. New auctions could provide greater revenue certainty, particularly for onshore wind developers.
Eroding onshore wind business case: Onshore wind continues to face challenging market conditions, including growing competition in the evening hours from utility-scale solar PV paired with battery storage, lengthy permitting procedures and long development timelines. Decisions on repowering part of the existing fleet may also affect capacity additions over the forecast period.
Grid development and system integration: Grid infrastructure, system operation and network planning need to evolve as rapidly as the generation mix to prevent emerging bottlenecks from constraining renewable deployment.
Electrification pace: Electricity accounts for only 25% of Spain's final energy consumption today. This is above the EU average of 23%, but considerable acceleration is required to reach the 2030 target of 35%. Spain has recently adopted several measures to speed up electrification, including the phase-out of the IVPEE electricity generation tax to better align electricity and gas taxation, tax incentives for heat pumps and self-consumption, and a EUR 400 million electric mobility programme. Faster electrification of heat and transport, renewable hydrogen development, data centres and industrial growth could raise electricity demand and support additional renewable deployment, although the pace of this demand growth remains uncertain.
What would it take for Spain to achieve the IEA accelerated forecast?
In the accelerated case, Spain's renewable capacity additions could be almost 40% higher than in the main case. Onshore wind and utility-scale solar PV would provide the largest upside, with additional contributions from distributed PV and pumped storage hydropower.
Faster storage deployment and hybrid projects: Faster deployment of short- and long-duration storage, together with regulatory clarity on hybrid configurations, would raise capture prices and reduce curtailment, strengthening the business case for utility-scale solar PV and onshore wind.
New auction rounds: Relaunching utility-scale auctions could provide the revenue certainty needed to expand the project pipeline, complementing merchant and corporate PPA-backed projects.
Faster permitting and stronger social acceptance: Rapid implementation of streamlined permitting, renewable benefit-sharing schemes and stronger stakeholder engagement, particularly for onshore wind, would shorten development timelines and increase project realisation rates.
Stronger demand from electrification: Faster electrification of transport, buildings and industry, together with accelerated reinforcement of transmission and distribution grids, would boost electricity demand, support higher capture prices and unlock additional corporate PPA demand for wind and solar PV. Spain's phase-out of the IVPEE electricity generation tax could also reduce the tax burden embedded in wholesale electricity prices, which could lower consumer electricity prices and accelerate electrification.
Stronger solar PV and wind outlook lifts Ukraine’s renewable forecast, although wartime risks weigh on delivery
How much renewable electricity capacity is Ukraine forecast to add by 2031?
- Ukraine is forecast to add almost 13 GW of renewable capacity over 2026–2031, nearly five times the volume added over 2020–2025. Net growth over 2020–2025 was relatively low because new capacity was partly offset by damage to existing plants following Russia’s full-scale invasion of Ukraine, particularly large hydropower and onshore wind facilities.
- Annual renewable capacity additions reached 1.3 GW in 2025 and are expected to average around 2.1 GW per year over 2026–2031.
- Solar PV accounts for 81% of renewable capacity additions over 2026–2031, followed by wind (14%), hydropower (4%) and bioenergy (1%).
Has the IEA revised its renewable electricity forecast for Ukraine compared to last year?
Summary: Ukraine’s renewable capacity forecast is revised up by almost 50% from last year’s edition, led by solar PV (+47%) and onshore wind (+12%). The upward revision for hydropower mainly reflects the expected restoration and repair of plants damaged following Russia’s full-scale invasion of Ukraine.
Solar PV: The forecast is revised up by 47%, from 5.7 GW to 8.4 GW over 2026–2030. Distributed PV accounts for most of the absolute revision, led by commercial systems, as businesses invest more than expected in self-consumption and backup supply. However, recent deployment levels remain uncertain, as many behind-the-meter systems are neither reported to distribution system operators nor formally registered, resulting in wide variation among estimates. New policy support also contributes households can receive a one-time reimbursement of 30% of the loan principal for solar- or wind-plus-storage systems, while condominium associations and housing co-operatives can receive grants covering up to 70% of eligible solar PV and storage costs. Utility-scale solar PV is revised up by 84%, from 1.0 GW to 1.9 GW, reflecting stronger-than-expected and renewed activity in large-scale projects.
Onshore wind: The forecast is revised up from 1.4 GW to 1.6 GW over 2026–2030, reflecting stronger-than-expected deployment in 2025 and almost 200 MW completed by year-end but awaiting commissioning. The second 2025 wind auction awarded 120 MW against a 150 MW quota, while the substantially larger 700 MW round in 2026 could further expand the pipeline.
Other technologies: Hydropower is revised up from a small net decline to around 0.5 GW of additions over 2026–2030, mainly reflecting the expected restoration and modernisation of damaged assets. The bioenergy forecast is unchanged.
What is driving renewable capacity growth in Ukraine?
Policy ambition: Ukraine’s updated National Energy and Climate Plan, approved in June 2026, envisages 23.7 GW of installed renewable capacity by 2030, including 14 GW of solar PV, 4.3 GW of wind and 4.7 GW of hydropower.
Competitive auctions: Ukraine is relaunching renewable auctions after limited uptake in 2024–2025. The 2026 rounds offer 700 MW of wind, 50 MW of standalone solar PV and 100 MW of solar PV paired with storage. Reforms adopted in 2026 replace the two-sided contract for difference with a one-sided market premium, extend auctions to 2034, lower financial-security requirements and create a separate solar-plus-storage auction category.
Distributed solar PV and storage: Energy security and resilience needs are driving households, businesses and public facilities to install solar PV and batteries, supported by a one-time reimbursement of 30% of household loan principal, preferential business loans and net billing.
What are the main challenges to renewable capacity growth in Ukraine?
Wartime and asset uncertainty: Ongoing attacks, occupation and damage create uncertainty over the operating fleet and disrupt construction, logistics and maintenance.
Financing and bankability: High capital costs, which have risen further since 2022, limited access to long-tenor debt and concerns over offtaker payments remain major barriers.
Grid restoration and connection: Damaged transmission and distribution networks, limited connection capacity and insufficient system flexibility constrain renewable integration, particularly as distributed solar PV expands.
Regulated household electricity prices: Below-cost household tariffs weaken the financial incentive for residential solar PV self-consumption and participation in net billing, although resilience needs and targeted financial support continue to sustain deployment.
Auction challenges: Payment delays by the Guaranteed Buyer and weaknesses in the previous auction design may have limited participation. The new market premium improves incentives but may not fully resolve revenue uncertainty.
What would it take for Ukraine to achieve the IEA accelerated forecast?
In the accelerated case, Ukraine’s renewable capacity additions could be almost one-third higher than in the main case. Solar PV offers the largest upside, followed by pumped-storage hydropower and onshore wind, with a smaller contribution from bioenergy.
Market and regulatory reform: Fair access to electricity and ancillary-service markets, greater temporal and locational granularity, and rules enabling batteries and aggregated distributed energy resources (DERs) to provide multiple services would strengthen project revenues and system value. Some of these reforms are already being rolled out as Ukraine transposes the EU Renewable Energy Directive (RED) and prepares for EU market coupling ahead of EU accession.
DER integration and visibility: Establishing a DER registry, expanding smart-meter deployment and improving system operators’ visibility, forecasting and control of behind-the-meter resources would allow more distributed capacity to be integrated securely.
Successful auction delivery: Strong participation in the 2026 auctions, timely contracting and high project realisation rates would build a credible utility-scale solar PV and wind pipeline.
More de-risking finance: Wider access to concessional finance and guarantees would lower financing costs and help more projects reach financial close.
Faster distributed solar PV uptake: Sustained funding for household support, wider access to business finance and more attractive net-billing rules would accelerate solar PV and battery deployment.
Grid reconstruction and flexibility: Faster network repair and expansion, shorter connection timelines and additional battery capacity would support greater renewable integration. Stronger TSO–DSO coordination and greater DSO capacity for local flexibility procurement, congestion management and voltage control would also be needed. Higher solar PV deployment would also increase storage and ramping requirements.
Strong policy support accelerates renewable deployment, while timely grid connection and policy implementation are key to project delivery
How much renewable electricity capacity is the United Kingdom forecast to add by 2031?
- The United Kingdom is forecast to add around 63 GW of renewable capacity over 2026–2031, almost three times than over 2020–2025.
- Annual renewable capacity additions exceeded 4 GW in 2025, 10% below the 2024 level, and are expected to average over 10 GW per year over 2026–2031.
- Solar PV accounts for 55% of renewable capacity additions over 2026–2031 and wind for 43%, with hydropower and bioenergy each contributing around 1% and ocean energy making a marginal contribution.
Has the IEA revised its renewable electricity forecast for the United Kingdom compared to last year?
Summary: The United Kingdom’s renewable capacity forecast is revised down by around 6% from last year’s edition, with diverging trends across technologies. Solar PV is revised upward (+4%), while wind (-14%), hydropower (-75%), bioenergy (-42%) and ocean (-35%) are revised down. Successful auctions continue to support utility-scale growth, but long grid connection queues and permitting delays are slowing solar PV and wind additions. For solar PV, rising distributed installations offset this slowdown. Several pumped-storage hydropower projects are under development, but long development and construction timelines mean only a limited share will be commissioned by 2031. Bioenergy capacity additions in 2025 were lower than expected, and future growth is limited as support for smaller anaerobic digestion plants expires from 2027, although incentives for biomethane production remain.
Offshore wind: Stronger auction outcomes and continued policy support continued growth. After AR5 awarded no offshore wind capacity, AR6 awarded around 5 GW and AR7 more than 8 GW. However, project realisation depends on securing timely grid connections.
What is driving renewable capacity growth in the United Kingdom?
Target: Under Clean Power 2030, the United Kingdom aims for clean sources to supply at least 95% of generation in a typical year by 2030, reducing the carbon intensity of generation to below 50 gCO2e/kWh.
Renewable auctions: Contracts for difference (CfD) auctions have awarded more than 50 GW of solar PV, wind, bioenergy and ocean capacity, with further rounds expected. The latest round (AR7) awarded a record 14.7 GW, including 8.4 GW of offshore wind, 4.9 GW of solar PV and 1.3 GW of onshore wind and tidal projects, strengthening the pipeline to 2030.
Solar Roadmap and distributed PV: The Solar Roadmap aims for 45–47 GW of solar capacity by 2030 and sets out actions on rooftop solar, grid connections, public buildings, car parks, skills and supply chains. Rooftop deployment is further supported by declining technology costs, the Smart Export Guarantee, which remunerates surplus generation exported to the grid, and high retail electricity prices, which encourage households and commercial consumers to reduce bills through self-consumption. The Future Homes Standard, which raises energy performance requirements for new homes, is also expected to encourage rooftop solar PV as a cost-effective compliance option.
Storage and infrastructure support: Short- and long-duration storage is increasingly important for integrating higher shares of wind and solar PV. The cap-and-floor regime for long-duration electricity storage sets a minimum revenue floor and a revenue cap for eligible projects, reducing investment risk for pumped-storage hydropower, flow batteries, compressed-air storage and longer-duration batteries. In parallel, the Planning and Infrastructure Act is expected to streamline planning and permitting, improve land access and accelerate the delivery of critical energy infrastructure, including transmission networks.
What are the main challenges to renewable capacity growth in the United Kingdom?
Grid queues: Over 700 GW of projects are waiting in grid queues. Recent reforms replacing the first-come, first-served approach with a “ready and needed” model are already delivering visible results. Under the new Gate 1 and Gate 2 process, projects meeting readiness and strategic alignment criteria receive confirmed connection positions, while less advanced projects no longer block the active queue. Several hundred GW of generation, storage and infrastructure projects have been prioritised to date.
Permitting: Project delivery depends not only on identifying sites with strong solar or wind resources, but also on securing land rights, environmental assessments, local community acceptance and governance approvals. Supporting measures have been announced (e.g. the Onshore Wind Taskforce), but their impact will depend on effective implementation and whether reforms shorten permitting timelines.
Implementation of policy reforms: The policy framework is supportive, but the pace of implementation remains a key uncertainty for project delivery and pipeline realisation.
What would it take for the United Kingdom to achieve the IEA accelerated forecast?
In the accelerated case, the United Kingdom’s renewable capacity could be almost 20% higher than in the main case. Upside spans all technologies, led by wind, followed by solar PV, hydropower and bioenergy.
Planning and land access: Effective implementation of planned permitting reforms could enable more utility-scale solar PV and onshore wind, together with the necessary storage and infrastructure projects, to be developed before 2031.
Wind repowering: Priority grid access and faster permitting for repowering could increase capacity at existing sites while limiting additional grid constraints.
Continued auctions: Future CfD rounds will need to maintain sufficient volumes while refining design rules to improve deliverability, including clearer eligibility, stronger delivery incentives and closer alignment with grid-readiness requirements (e.g. the planned exclusion from AR8 of applications with only a Gate 1 connection offer).
Accelerating offshore wind grid connections: Several major offshore wind projects awarded in AR7 face grid connection uncertainty. Faster firm connection offers, transmission build-out and coordinated offshore grid development would be critical to bring more offshore wind online before 2031.
Provincial procurement becomes the main growth driver as merchant and corporate PPA-backed deployment slows
How much renewable electricity capacity is Canada forecast to add by 2031?
- Canada is forecast to add 21.7 GW of renewable capacity over 2026–2031, 77% more than in 2020–2025.
- Annual additions fell 37% year-on-year to around 1.3 GW in 2025, but are expected to average about 3.6 GW per year over 2026–2031.
- Onshore wind accounts for more than half (56%) of additions over 2026–2031, followed by solar PV (37%) and hydropower (6%), while bioenergy and geothermal contribute marginally.
Has the IEA revised its renewable electricity forecast for Canada compared to last year?
Summary: Canada’s renewable capacity forecast is revised down by around 13% from last year, with diverging trends across technologies. The largest downward revisions are for hydropower (-55%) and solar PV (-21%), while bioenergy is revised down by 9% from a small base. The onshore wind forecast is broadly unchanged (+2%).
Solar PV: The forecast is revised down as weaker merchant and corporate PPA activity reduces the utility-scale project pipeline. This is partly offset by a more optimistic distributed PV outlook, driven by commercial deployment and stronger residential growth, as provincial programmes cushion the phase-out of the Canada Greener Homes Initiative.
Onshore wind: The forecast is broadly unchanged despite lower 2025 additions and a weaker near-term pipeline, particularly in Alberta, where permitting restrictions and market uncertainty have weighed on investment. Growth is expected to recover from 2027, supported by provincial procurement and a gradual recovery in corporate PPA activity.
Others: Conventional hydropower is revised down, as the large-scale Amisk Hydroelectric Project withdrew from the federal impact assessment process in 2026, while the Petit-Mecatina Hydro Project remains at an early stage and is not expected to be commissioned within the forecast period. Pumped storage hydropower (PSH) is excluded from the main case because no major project is currently expected to be commissioned by 2031: the Canyon Creek PSH Project was cancelled in 2025, the Ontario Pumped Storage Project was postponed to 2035, the Tent Mountain PSH Project has been delayed, and development of the Marmora PSH Project has been paused. Bioenergy and other renewables remain marginal contributors.
What is driving renewable capacity growth in Canada?
Provincial procurement: While Alberta’s competitive auctions and corporate PPA market historically drove growth, deployment is increasingly underpinned by procurement in other provinces. In 2026, Ontario and British Columbia each awarded over 1.1 GW of wind and solar PV capacity, for commissioning by 2030 and 2033, respectively. Québec, Saskatchewan and New Brunswick are advancing additional procurement rounds.
Corporate PPAs: Corporate procurement remains an important driver. Ontario’s new framework allowing large consumers to sign offsite PPAs could expand the market beyond Alberta, although uptake will depend on electricity demand growth and project economics.
Federal incentives: The Clean Electricity and Clean Technology Investment Tax Credits improve the investment case for renewable projects, supporting their participation in both provincial procurement and corporate PPA markets.
What are the main challenges to renewable capacity growth in Canada?
Policy and market uncertainty in Alberta: Regional policy, permitting and market design changes continue to weigh on merchant and corporate PPA-backed wind and solar PV projects. In Alberta, post-moratorium land-use restrictions and electricity market reforms have weakened investor confidence and reduced the project pipeline.
Grid connection: Interconnection constraints and connection queues continue to delay both utility-scale solar PV and onshore wind projects.
Project realisation: Merchant and corporate PPA-backed projects remain exposed to revenue, offtake and financing risks, while projects awarded in provincial auctions can still face permitting, land-use and grid connection delays before reaching commercial operation.
Hydropower timelines: Long development timelines, high upfront costs and complex permitting limit the contribution of large conventional hydropower and PSH projects before 2031 in the main case.
What would it take for Canada to achieve the IEA accelerated forecast?
In the accelerated case, Canada’s renewable capacity additions are around one-third higher than in the main case. Onshore wind offers the largest upside, followed by solar PV and hydropower, while bioenergy and geothermal make smaller contributions.
Stronger provincial procurement: Larger and more timely procurement volumes across provinces, combined with higher realisation rates for awarded solar PV and onshore wind projects.
Alberta pipeline recovery: Improved investment conditions in Alberta would support new wind and solar PV development and help rebuild the project pipeline.
Faster corporate PPA growth: Timely implementation of Ontario’s offsite PPA framework, together with similar initiatives in other provinces, would improve revenue certainty for projects outside regulated markets.
Grid and interconnection improvements: Faster grid connection, better queue management and lower interconnection costs would support onshore wind and utility-scale solar PV, while greater distribution grid capacity would enable more behind-the-meter solar PV.
Timely hydropower and PSH delivery: Faster development of conventional hydropower and PSH projects would provide additional upside, including if delays to the Tent Mountain PSH Project were overcome and the project were commissioned by 2031.
Solar PV drives Mexico’s renewable growth as utility-scale procurement resumes
How much renewable electricity capacity is Mexico forecast to add by 2031?
- Mexico is forecast to add 22 GW of renewable capacity over 2026–2031, double the amount added in 2020–2025.
- Annual additions fell by one-fifth year-on-year to 1.7 GW in 2025 but are expected to average around 3.6 GW per year over 2026–2031.
- Solar PV accounts for the vast majority (92%) of additions over 2026–2031, followed by onshore wind (5%) and hydropower (4%).
Has the IEA revised its renewable electricity forecast for Mexico compared to last year?
Summary: Mexico’s renewable capacity forecast is revised down by 19% from last year. The largest downward revisions are for onshore wind (−66%) and distributed solar PV (−39%), while utility-scale solar PV (+31%) is the only technology revised up.
Solar PV: The overall downward revision masks contrasting segment trends. Distributed PV is revised down by around one-third owing to slower-than-expected expansion, although it remains one of the country’s leading renewable technologies. In contrast, utility-scale PV is revised up by around one-third, as solar PV secured a larger-than-expected share of capacity in the latest auction.
Onshore wind: The forecast is revised down by around two-thirds, as the latest auction awarded less capacity than expected.
What is driving renewable capacity growth in Mexico?
Target: Mexico aims to reach close to 55 GW of installed renewable capacity by 2030. In 2024, the administration announced a target of 45% clean electricity generation by 2030, later reinforced by the Energy Sector Program 2025–2030 (published in May 2025), which sets out priorities for renewable deployment, grid expansion and clean energy investment.
Auction: Mexico held its first auction under a new mixed public-private procurement scheme, in which the Federal Electricity Commission (CFE) partners directly with private developers, sharing investment and risks while retaining stronger state control than under the previous long-term auction framework. The auction awarded almost 7.5 GW, exceeding the government’s 6.5 GW target, with projects concentrated in Yucatán and the Northeast. This marks a major reopening of large-scale private renewable development, albeit through a CFE-led model.
Distributed solar PV: Net metering remains attractive for consumers, while the increase in the system-size threshold from 500 kW to 700 kW broadens the distributed PV market over the coming years.
What are the main challenges to renewable capacity growth in Mexico?
Grid infrastructure: Limited transmission capacity and grid expansion delays could restrict the integration of new projects, particularly in high-resource areas such as northern Mexico and the Yucatán Peninsula.
Permitting and project delays: Complex approval processes, environmental requirements and land access challenges can extend project timelines and raise development costs.
What would it take for Mexico to achieve the IEA accelerated forecast?
In the accelerated case, Mexico’s renewable capacity additions are around 32% higher than in the main case, with solar PV offering the largest upside.
Faster utility-scale deployment: Accelerating subsidy-free utility-scale solar PV development would require stronger investor confidence, faster permitting and a more predictable regulatory framework to sustain a pipeline of new projects.
Higher distributed solar PV adoption: Broader uptake of net metering among residential, commercial and industrial consumers would be key to expanding distributed PV, supported by greater consumer awareness, attractive economics and easier access to rooftop solar PV.
Growing data centre electricity demand and rapid solar PV deployment drive United States renewable expansion
How much renewable electricity capacity is the United States forecast to add by 2031?
- The United States is forecast to add almost 314 GW of renewable capacity over 2026–2031, 30% more than over 2020–2025.
- Annual renewable capacity additions reached almost 49 GW in 2025. Over 2026–2031, annual additions are expected to average around 52 GW, with strong near-term deployment followed by slower growth later in the forecast period.
- Solar PV is set to account for almost 90% of renewable capacity additions over 2026–2031, with wind contributing most of the remainder. Hydropower, geothermal, bioenergy and CSP add only marginal capacity.
Has the IEA revised its renewable electricity forecast for the United States compared to last year?
Summary: The United States renewable capacity forecast is revised up by around 40% from last year’s edition, mainly due to stronger solar PV deployment across utility-scale, commercial and industrial, and residential segments. Utility-scale solar PV accounts for the largest upward revision, while onshore wind is revised up by around 10%.
Solar PV: The forecast is revised up significantly on stronger-than-expected deployment and a larger near-term pipeline of projects seeking to qualify for federal tax credits before eligibility deadlines. Utility-scale solar PV accounts for most of the upward revision while commercial and industrial growth remains robust on corporate demand and improving economics. A growing pipeline of solar-plus-storage projects further supports the revision by improving project economics and reducing exposure to declining capture prices and negative-price events.
Wind: The wind forecast is also revised up. Stronger near-term deployment is supported by projects seeking to qualify for existing tax credits, but growth moderates after 2027 as federal incentives phase down or expire and permitting challenges persist. Offshore wind remains constrained by the temporary halt on new federal leasing, permitting and approvals.
Others: Geothermal is revised up by over 20% on a stronger project pipeline and growing interest in enhanced geothermal systems, supported by federal and state initiatives. Hydropower and bioenergy remain marginal, and their outlook reflects the ageing of the existing fleet rather than new-build growth. The forecast assumes some bioenergy retirements, while hydropower additions come mainly from the refurbishment and modernisation of large existing plants.
What is driving renewable capacity growth in the United States?
Demand for dispatchable clean power: Utilities and corporate buyers increasingly seek dispatchable clean power and system flexibility, supporting investment in geothermal, battery storage and hybrid renewable projects. Rapid growth in utility-scale battery storage enables higher solar PV penetration by reducing curtailment and improving project economics.
Tax credit qualification rush: Developers are accelerating construction to secure federal tax credits before eligibility expires, creating a strong near-term pipeline for solar PV and wind. Safe-harbour provisions allow qualifying projects to retain access to federal support beyond the initial construction deadline.
State-level policies: Renewable portfolio standards, clean energy standards and state procurement programmes are expected to become increasingly important drivers of deployment as federal incentives phase down or expire.
Corporate PPAs and electricity demand growth: Corporate procurement remains a major source of demand, particularly from data centres and large industrial consumers seeking long-term price certainty and to meet decarbonisation commitments. Corporate PPAs are set to play a larger role once federal incentives expire.
Utility-scale solar PV competitiveness: Utility-scale solar PV remains one of the lowest-cost sources of new generation in many regions, supporting deployment despite policy uncertainty and changes to support mechanisms.
What are the main challenges to renewable capacity growth in the United States?
Post-2027 policy uncertainty: The phase-down or phase-out of tax credits under the One Big Beautiful Bill Act (OBBBA), evolving foreign entity of concern (FEOC) requirements and uncertain implementation rules reduce long-term visibility for developers and investors.
Federal permitting and land access: Changes to federal leasing, permitting and approval processes have increased uncertainty for projects requiring access to federal lands and waters. As most solar PV is deployed on private land, these changes are expected to affect wind more, particularly offshore wind.
Offshore wind halt: The temporary halt on new or renewed offshore wind leasing, permitting and approvals pending federal review has significantly weakened the offshore wind outlook and increased uncertainty for future projects.
Supply chain and trade measures: Tariffs on imported solar PV equipment and FEOC compliance requirements raise project costs and could constrain equipment availability, particularly after federal incentives expire.
Grid connection queues and transmission constraints: Long interconnection queues and insufficient transmission infrastructure continue to delay commissioning and raise development costs. Despite ongoing queue reforms, interconnection delays remain a major barrier in several regions.
Wholesale market revenues: Rapid solar PV growth is expected to intensify competition during daylight hours and put downward pressure on wholesale prices, making storage and corporate PPAs more important for project revenues.
Siting and land use: Growing local opposition and stricter county-level land-use rules are limiting available sites for solar PV and wind in some regions.
What would it take for the United States to achieve the IEA accelerated forecast?
In the accelerated case, renewable capacity additions in the United States could be 3% higher than in the main case. The largest upside would come from solar PV, followed by wind and geothermal.
Greater policy certainty: Clear implementation rules for tax credits and FEOC requirements would improve investment visibility and support a larger project pipeline.
Faster transmission expansion and interconnection reform: Accelerating transmission build-out and reducing interconnection queue delays would allow more solar PV and wind projects to reach commercial operation within the forecast period.
Stronger corporate procurement: Higher corporate PPA demand from data centres, manufacturing and other industrial consumers would provide additional revenue certainty once federal incentives expire.
Improved permitting and siting: Streamlined permitting and shorter approval timelines would raise project realisation rates for solar PV, wind and geothermal.
Faster deployment of storage and flexibility: Additional battery storage, demand response and grid flexibility would improve renewable integration and support higher solar PV and wind deployment.
Distributed solar PV drives Brazil’s renewable growth as utility-scale projects face grid integration challenges
How much renewable electricity capacity is Brazil forecast to add by 2031?
- Brazil is forecast to add almost 90 GW of renewable capacity over 2026–2031, broadly in line with additions in 2020–2025.
- Annual additions fell by one-third year-on-year to 15 GW in 2025 and are expected to remain at around this level, averaging 15 GW per year over 2026–2031.
- Solar PV accounts for the vast majority (87%) of additions over 2026–2031, followed by onshore wind (9%), bioenergy (3%) and hydropower (1%).
Has the IEA revised its renewable electricity forecast for Brazil compared to last year?
Summary: Brazil’s renewable capacity forecast is revised up by nearly 20% from last year, with diverging trends across segments. Distributed solar PV is revised up significantly (+74%), while utility-scale solar PV (−24%) and onshore wind (−15%) are revised down.
Solar PV: The overall upward revision masks contrasting segment trends. Utility-scale PV deployment is slowing owing to fewer auctions, growing transmission bottlenecks and rising curtailment. In contrast, the distributed PV outlook is more optimistic, as new grid-use charges have had a smaller impact than expected: falling solar PV costs have largely offset the additional grid costs, keeping the business case attractive.
Onshore wind: The forecast is revised down slightly owing to fewer auctions, growing transmission bottlenecks and rising curtailment, which weighs on the revenues of market-based projects.
What is driving renewable capacity growth in Brazil?
Energy Plan: Brazil projects to reach 255 GW of installed renewable capacity by 2030 under the Ten-Year Energy Expansion Plan 2035.
Free electricity market: Brazil’s electricity contracting is split between the Regulated Contracting Environment (ACR), where distributors procure through public auctions, and the Free Contracting Environment (ACL or Mercado Livre), where large consumers negotiate directly with generators. As renewable prices fell and became more competitive, many new wind and solar PV projects opted to sell through private power purchase agreements (PPAs) in the ACL rather than in regulated auctions.
Distributed solar PV: Brazil’s net metering remains highly attractive, allowing consumers to offset relatively high electricity tariffs with self-generated and consumed solar PV generation. Declining costs, improved financing options and strong solar resources keep the business case compelling, despite additional grid charges under the updated regulatory framework.
Enablers: Transmission auctions and policy mechanisms supporting storage deployment are key enablers of renewable growth.
What are the main challenges to renewable capacity growth in Brazil?
Fewer auctions: Lower demand for regulated contracts has reduced the number of competitive renewable auctions. Developers are increasingly relying on private PPAs and the free electricity market to build new capacity.
Grid infrastructure: Limited transmission capacity has become a key bottleneck, particularly in the Northeast, where the best wind and solar resources are concentrated. Delays in grid expansion and connection slow project development and raise investment risks.
Curtailment: Grid congestion and operational constraints are forcing wind and solar PV generators to reduce output, creating uncertainty for investors and weakening the bankability of future projects.
What would it take for Brazil to achieve the IEA accelerated forecast?
In the accelerated case, Brazil’s renewable capacity additions are around 10% higher than in the main case. Solar PV offers the largest upside, followed by onshore wind.
Faster grid expansion: Faster transmission build-out would allow more renewable capacity to connect and ease current bottlenecks.
Faster storage deployment: Battery deployment is emerging, but a faster and larger-scale rollout would help ease growing system integration challenges, including curtailment.
World-class resources sustain Chile’s renewable growth as storage and grid expansion become increasingly important
How much renewable electricity capacity is Chile forecast to add by 2031?
- Chile is forecast to add 20 GW of renewable capacity over 2026–2031, 14% more than in 2019–2025.
- Annual additions fell 5% year-on-year to 2.9 GW in 2025, but are expected to average around 3.4 GW per year over 2026–2031.
- Solar PV accounts for almost 60% of additions over 2026–2031, followed by onshore wind (40%).
Has the IEA revised its renewable electricity forecast for Chile compared to last year?
Summary: Chile’s renewable capacity forecast is revised down by 6% from last year, mainly owing to solar PV (−10%). Forecasts for other technologies are broadly unchanged.
Solar PV: 2025 additions fell short of projections, and some capacity is shifted to later years. While the underlying project pipeline is broadly unchanged, growing transmission and grid integration challenges add uncertainty, particularly towards the end of the forecast period.
What is driving renewable capacity growth in Chile?
Target: Chile aims to reach 51 GW of renewable capacity by 2030 under the Ministry of Energy’s National Energy Policy (Transición Energética de Chile, Política Energética Nacional).
Renewable resource availability: Chile has some of the world’s best solar and wind resources, with among the highest solar irradiance globally in the Atacama Desert and strong wind potential, particularly in the south.
Corporate PPAs: Corporate PPAs offer a growing complementary route to market for solar PV and onshore wind projects. Interest from large electricity consumers is rising, making PPAs increasingly attractive to developers as auctions are scaled back or delayed.
System integration investments: To address transmission and system integration constraints, Chile is strengthening regulatory frameworks and accelerating investment in transmission networks and energy storage, improving grid flexibility and supporting continued capacity growth.
What are the main challenges to renewable capacity growth in Chile?
Auction uncertainty: Although Chile continues to hold regulated electricity supply auctions, procurement volumes have fallen and some long-term auctions have been rescheduled or replaced by smaller short-term tenders, owing to lower electricity demand forecasts and contract revisions. This reduces long-term revenue visibility for new projects and may delay investment decisions.
Slow demand growth: Weak electricity demand growth limits the absorption of additional renewable output. Faster electrification of transport, mining, industry and heating will be critical to support further capacity expansion.
Grid infrastructure: Limited transmission capacity and grid expansion delays restrict the integration of new projects, particularly in high-resource areas such as the Atacama Desert in northern Chile, leading to congestion and curtailment.
Curtailment: Supply–demand imbalances and limited transmission capacity between generation hubs in the north and the main consumption regions in the centre and south constrain Chile’s renewable output. Curtailment of variable renewables reached around 15% in 2025, reducing the profitability of existing projects and weakening the outlook for planned ones, making it a key forecast uncertainty.
Zero-price hours: Zero-price hours have risen rapidly, particularly in the north, where excess solar generation, transmission bottlenecks and operational constraints result in frequent midday periods with marginal costs near zero. In some months, zero-price hours exceeded 30–40% of the total in northern areas, reducing project profitability and challenging new investment unless supported by storage, long-term contracts or grid upgrades.
What would it take for Chile to achieve the IEA accelerated forecast?
In the accelerated case, Chile’s renewable capacity additions are around 18% higher than in the main case, with utility-scale solar PV and onshore wind offering the largest upside.
Faster grid expansion: Accelerating transmission and distribution build-out would ease congestion, particularly on the corridor linking northern Chile’s high-resource areas with central demand centres, allowing renewable plants to operate at higher utilisation and reducing curtailment.
Faster storage deployment: Energy storage is a key solution to Chile’s integration challenges. Faster battery rollout would reduce the magnitude and frequency of supply–demand imbalances, increase the use of surplus solar PV generation and improve grid flexibility.
Rising electricity demand: Higher demand would absorb renewable generation that is currently under-utilised. Stronger demand from mining, electrification and emerging industries such as renewable hydrogen would support higher deployment and improve project economics.
Saudi Arabia’s renewable capacity expansion is set to accelerate after record additions in 2025, thanks to strong government policies, but supply-chain and grid-integration challenges may delay some projects in the near term
How much renewable electricity capacity is Saudi Arabia forecast to add by 2031?
- Saudi Arabia is forecast to add 61 GW of renewable capacity over 2026‑2031, more than four times the amount added over 2020‑2025.
- Annual additions reached almost 9 GW in 2025 and are expected to rise to around 12 GW by 2031.
- Utility-scale solar PV accounts for 87% of additions over 2026‑2031, with onshore wind making up the remaining 13%.
Has the IEA revised its renewable electricity forecast for Saudi Arabia compared to last year?
Summary: The forecast for Saudi Arabia is revised down slightly (-3%), reflecting slower-than-expected progress in onshore wind auctions and the risk that supply-chain disruptions and system-integration constraints delay some projects by a year.
Solar PV: The forecast is revised down slightly, as supply-chain disruptions and system-integration constraints are expected to extend project lead times. Imports of solar PV modules from China fell two-thirds year-on-year in Q1‑Q3 2026. One developer cited potential project delays of 6‑12 months and greater planning challenges amid regional geopolitical volatility. The forecast also accounts for system-integration risks, following the curtailment of, and dispatch restrictions on, two projects totalling 3.8 GW (DC) in late 2025 and early 2026 owing to grid-stability concerns.
Onshore wind: The forecast is revised down by almost 10%, as new auctions held in 2025 for 2 GW set commissioning deadlines later than expected.
What is driving renewable capacity growth in Saudi Arabia?
Target: Saudi Arabia aims to reach 130 GW of renewable energy capacity by 2030 under its Vision 2030 strategy, which also seeks a 50% renewables share in power generation by 2030 and greater economic diversification through a higher share of non-oil GDP.
Rapid power demand growth and oil displacement: Rising electricity demand and the need to reduce oil-fired generation are key drivers of renewable capacity expansion. Peak load reached a record 77 GW in 2025, 24% higher than in 2015, driven by population and non-oil economic growth, as well as greater electricity needs for cooling, electrification and desalination. The Liquid Fuel Displacement Program aims to cut domestic liquid-fuel consumption by around 1 million barrels per day, freeing oil for higher-value uses such as refining and exports. Renewables are a key component of the programme, helping to meet higher demand while reducing oil burn in power generation.
Clear and stable procurement policy: The government plans to meet its renewable energy target through a two-track procurement system, with 70% of capacity secured through unsolicited bilateral contracts and 30% through competitive power purchase agreement (PPA) auctions. The bilateral track is led by the Public Investment Fund, Saudi Arabia’s sovereign wealth fund, which takes an equity stake in the projects. Competitive auctions are run by the Saudi Power Procurement Company and have delivered some of the world’s lowest electricity tariffs for solar PV.
Storage and system-integration investment: Saudi Arabia is rapidly expanding energy storage alongside renewables. Commissioned in 2025, the Bisha battery energy storage system (BESS) was at the time the world’s largest grid-connected battery, and BESS is increasingly procured together with large-scale solar PV projects to support system integration.
Attractive economics for solar PV: Saudi Arabia has achieved two of the world’s lowest solar PV tariffs: USD 10.4/MWh for a 600 MW project in 2021 and USD 11/MWh for a 1.4 GW project in 2025. These low prices are partly the result of excellent solar resources, economies of scale from large projects and favourable financing conditions.
What are the main challenges to renewable capacity growth in Saudi Arabia?
Supply-chain and project-cost uncertainty: The closure of the Strait of Hormuz has disrupted equipment deliveries and created uncertainty over project costs, potentially extending lead times. Saudi solar PV module imports from China fell two-thirds in Q1‑Q3 2026, while freight rerouting, along with higher insurance premiums and financing costs, could prompt contract renegotiations or delay final investment decisions. Some developers have indicated that these impacts of geopolitical uncertainty could delay projects in the near term.
System integration: Rapid renewable capacity deployment is putting increasing pressure on the power system to integrate large volumes of variable generation. The grid operator placed dispatch restrictions on the 1.6 GW Al Kahfah and 2.3 GW Ar Rass 2 solar PV plants from December 2025 and January 2026, respectively, citing reactive-power fluctuations affecting grid stability.
What would it take for Saudi Arabia to achieve the IEA accelerated forecast?
In the accelerated case, Saudi Arabia’s renewable capacity additions are almost 20% higher than in the main case, reaching 71 GW. Solar PV offers the largest upside, followed by onshore wind.
More frequent auction rounds: Holding competitive renewable electricity auctions more often would secure additional capacity for development.
More flexibility from batteries and grid upgrades: Faster battery deployment, along with timely grid upgrades and interconnections, would strengthen system flexibility, enabling additional solar PV and wind capacity. Finding cost-effective ways to make long-term contracts with conventional (non-renewable) generators more flexible would also reduce the risk of renewable curtailment.
Enabling corporate procurement: Allowing industrial consumers to buy power directly from developers would also encourage additional renewable capacity.
Egypt’s renewable capacity forecast nearly doubles as the government brings forward its target and accelerates procurement to strengthen energy security and reduce costly fuel imports amid the current conflict in the Middle East
How much renewable electricity capacity is Egypt forecast to add by 2031?
- Egypt is forecast to add 13 GW of renewable capacity over 2026‑2031, more than four times the amount added over 2020‑2025.
- Annual additions reached a record 1.2 GW in 2025 and are expected to rise to almost 4 GW by 2031.
- Utility-scale solar PV accounts for 63% of additions over 2026‑2031, with onshore wind making up the remaining 37%.
Has the IEA revised its renewable electricity forecast for Egypt compared with last year?
Summary: Egypt’s forecast has been revised up significantly (+91%), reflecting the acceleration of plans already under way in response to the sharp rise in gas import costs caused by the current conflict in the Middle East. In March 2026, the government reported that the country’s monthly natural gas import bill had nearly tripled since the start of the conflict (from USD 560 million to USD 1.65 billion). It also brought forward its 45% renewable electricity target from 2035 to 2028. This acceleration builds on reforms already in place, including a growing pipeline of large bilateral wind, solar PV and storage projects, a new framework for corporate power purchase agreements (PPAs) and the reintroduction of competitive wind and solar PV auctions.
Onshore wind: The forecast has been revised up modestly (+11%) to reflect new PPAs signed between developers and the state-owned utility.
Solar PV: The forecast has been revised up more than fourfold, from 1.5 GW to 6.5 GW for 2026‑2030, reflecting a sharp expansion of the project pipeline in two procurement tracks. First, unsolicited bilateral projects with the utility advanced over the past year through new PPAs, equipment orders and memoranda of understanding, including a 2 GW PPA. Second, over 1.4 GW of corporate PPAs are under development. These include a large project for an aluminium producer seeking to meet EU Carbon Border Adjustment Mechanism (CBAM) requirements. They also include at least 200 MW of solar PV approved under the government’s private-to-private (P2P) pilot programme, which for the first time enables generators to sell electricity directly to industrial consumers over the grid.
What is driving renewable capacity growth in Egypt?
Target: In 2026, the government brought forward its 45% renewable electricity target from 2035 to 2028 to strengthen energy security in response to the current conflict in the Middle East.
Rising power demand: Egypt’s electricity demand grew around 1.5% in 2025 and is expected to increase 2.3% annually to 2030, driven by higher industrial consumption, population growth and cooling needs. In August 2026, seasonal peak demand reached a record 40.2 GW, surpassing the previous high set just a year earlier.
Energy security and lower fuel imports: Reducing reliance on fossil fuel imports and exposure to price volatility is a key driver of accelerated renewable electricity deployment and the higher targets announced in 2026. Although Egypt produces oil and gas, it relies on fuel imports to meet its power needs. In 2024, natural gas accounted for around 76% of electricity generation and oil products for a further 10%, with an estimated 33% of power plant fuel supplied by imports. In July 2026, natural gas imports exceeded domestic production for the first time as the country sought to meet record peak demand, reduce oil burn for power and avoid load shedding. This dependence has become increasingly costly amid the current conflict in the Middle East: in March 2026, the government reported that the monthly gas import bill had nearly tripled, from USD 560 million to USD 1.65 billion.
Corporate procurement advancing: Egypt’s 2015 Electricity Law allowed independent power producers to use the grid to sell electricity directly to consumers, but implementing rules, including on grid access and wheeling charges, had yet to be developed. In 2025, a P2P pilot put this framework into operation, approving four projects totalling 400 MW to supply industrial consumers in the steel, cement and silicon sectors. Separately, an aluminium producer signed a 1.1 GW corporate PPA with Scatec to decarbonise its exports ahead of EU CBAM requirements.
Competitive auctions reintroduced: After an absence of around 10 years, the government restarted competitive PPA auctions in 2025‑26, launching tenders for 1 GW of onshore wind and 500 MW of solar PV.
What are the main challenges to renewable capacity growth in Egypt?
Limited policy visibility: Beyond projects already contracted or under procurement, visibility over additional capacity remains low. Although competitive auctions have restarted, there is no forward auction schedule, and corporate procurement is capped at 500 MW under the P2P pilot, with uncertainty over approvals beyond this level.
System integration: The government recognises that the pace of renewable capacity deployment depends on grid expansion and system flexibility keeping up with new capacity. Battery storage is expanding rapidly, from around 500 MWh installed in mid-2026 towards a target of 14.3 GWh by end-2028, with several large projects already under construction or backed by signed PPAs. In parallel, the utility has been granted EUR 1.6 billion for a transmission modernisation programme to strengthen the grid and enable the integration of 22 GW of renewables by 2030, while the 3 GW interconnector with Saudi Arabia is nearing completion. Timely delivery of these investments will influence how quickly renewable capacity deployment can scale up.
Project bankability: Currency volatility, high financing costs and offtaker risk continue to constrain project bankability. Recent utility-scale PPAs mitigate these risks through USD-denominated tariffs and sovereign guarantees, while projects remain heavily reliant on international development finance and risk guarantees.
What would it take for Egypt to achieve the IEA accelerated forecast?
In the accelerated case, Egypt’s renewable capacity additions are 50% higher than in the main case, an increase of 6.5 GW. Onshore wind offers the largest upside, followed by solar PV.
More frequent and predictable competitive auctions: Establishing a forward auction schedule and holding competitive tenders more regularly would give investors greater visibility over the government’s plans to procure additional capacity.
Expanding corporate procurement: Scaling up the P2P framework beyond the current 500 MW pilot and allowing a broader range of consumers to buy renewable electricity directly from developers would unlock additional corporate demand.
Improving project bankability: Reducing offtaker and currency risks, and improving access to affordable financing, would help projects reach financial close and reduce their reliance on sovereign guarantees and concessional finance.
Faster deployment of batteries, grids and interconnections: Timely delivery of planned battery storage, transmission upgrades and interconnections would provide the flexibility and grid capacity needed to accommodate additional solar PV and wind.
Demand for reliable electricity accelerates distributed solar PV growth in Nigeria
How much renewable electricity capacity is Nigeria forecast to add by 2031?
- Nigeria is forecast to add 20 GW of renewable capacity over 2026–2031, representing a 285% acceleration compared with the 2019–2025 period.
- Annual renewable capacity additions reached a record 2 GW in 2025, 68% above the 2024 level, and are forecast to average more than 3 GW per year over 2026–2031.
- Solar PV is set to provide 99% of Nigeria’s renewable capacity additions over 2026–2031, with hydropower accounting for the remaining 1%.
Has the IEA revised its renewable electricity forecast for Nigeria compared to last year?
Summary: Nigeria's renewable capacity forecast is revised up by 50% compared with last year's edition, with diverging trends across technologies. Notable downward revisions include utility-scale solar PV (−81%), and hydropower (-61%), while distributed solar PV (+195%) is revised up significantly.
Solar PV: The solar PV forecast has been revised up significantly, but this masks diverging trends across market segments. Distributed solar PV is revised sharply upwards as higher diesel costs, falling solar PV and battery prices, improved mini-grid regulations and the introduction of net billing strengthen the economics of commercial, industrial and residential systems. By contrast, utility-scale solar PV is revised downwards due to state-owned utility payment risks, transmission constraints and the absence of a dedicated procurement framework.
Other technologies: Hydropower is revised downwards due to limited progress on large-scale projects. Although almost 5 GW remains under development, most projects are now forecast to be commissioned after 2031. No wind, bioenergy, CSP or geothermal additions are forecast during 2026–2031.
What is driving renewable capacity growth in Nigeria?
National targets: Nigeria’s Third Nationally Determined Contribution, released in September 2025, targets greenhouse gas emissions reductions of 29% by 2030 and 32% by 2035 compared to 2018 levels, alongside net zero emissions by 2060. It also targets universal electricity access and a 50% renewable share of power generation by 2030, and a 52% renewable share of total generation capacity by 2035, including 10.4 GW of hydropower and 5.7 GW of solar PV. The National Integrated Resource Plan (2024) provides a long-term framework for power-sector development through 2045.
Regulatory reforms: The 2023 amendment to the Electricity Act liberalised the power sector, enabling states and private entities to generate, distribute and trade electricity. The 2026 Mini-Grid Regulations and Net Billing Framework further support distributed solar PV by expanding market access, simplifying licensing and improving project economics.
Diesel displacement and unreliable grid supply: The removal of fuel subsidies in 2023 and persistent grid reliability challenges continue to accelerate distributed solar PV and storage adoption among households and businesses seeking alternatives to diesel generation.
Distributed access and off-grid programmes: Rural Electrification Agency initiatives, including the Nigerian Electrification Programme and the USD 750 million DARES programme support deployment of mini-grids, solar home systems and institutional solar PV projects.
Domestic manufacturing: Nigeria attracted more than USD 400 million of renewable energy investment in 2025, supporting the development of eight manufacturing facilities. Domestic PV module assembly capacity could exceed 500 MW per year in 2026 and is forecast to surpass 1 GW annually by 2031, driven by increasing policy and regulatory efforts to promote local manufacturing. Imports of more than 3 GW of solar PV components from China in the first half of 2026, almost two-thirds of which were cells, indicate rising local assembly activity.
What are the main challenges to renewable capacity growth in Nigeria?
Project bankability and financing: Offtaker risk remains a major constraint, as weak revenue collection by distribution companies undermines the bankability of utility-scale projects. Limited financing access, weak creditworthiness among commercial and industrial customers, and foreign-exchange volatility also constrain distributed solar PV deployment.
Grid infrastructure and transmission constraints: The National Integrated Resource Plan (2024) indicates that only around half of installed grid generation capacity is utilised because of transmission limitations. Congestion and curtailment risks constrain utility-scale renewable deployment and increase the need for decentralised solutions.
Storage regulation: Battery storage deployment is increasing alongside distributed solar PV and mini-grids, but the absence of a dedicated regulatory framework for grid-connected storage constrains further scale-up.
Uncertainty over solar PV import policy: Proposed restrictions on imported solar PV modules to support domestic manufacturing could slow near-term deployment if local production capacity does not expand sufficiently.
Lack of utility-scale procurement: While support for distributed and off-grid solar PV is strengthening, the absence of a competitive procurement framework for utility-scale renewables continues to limit the pipeline of grid-connected projects.
What would it take for Nigeria to achieve the IEA accelerated forecast?
In the accelerated case, Nigeria’s renewable capacity additions could be 77% higher than in the main case. Onshore wind offers the largest upside potential, followed by solar PV and conventional hydropower.
Grid expansion and network investment: Faster delivery of transmission and distribution investments identified in the National Integrated Resource Plan (2024) would reduce congestion, unlock underutilised generation capacity and enable the connection of new utility-scale renewable and hydropower projects.
Improved project bankability: Strengthening distribution company finances, reducing offtaker risks and expanding access to local-currency financing would improve the viability of utility-scale renewable projects.
Clear storage regulation: Dedicated rules for battery storage interconnection and market participation would accelerate deployment and support the integration of variable renewables.
Dedicated utility-scale procurement: A competitive procurement framework for utility-scale solar PV and onshore wind would strengthen the project pipeline and improve long-term revenue visibility.
Scaling domestic manufacturing: Timely delivery of planned module assembly capacity, alongside sustained support for a domestic solar manufacturing ecosystem, would help expand solar PV deployment.
Solar PV leads South Africa's renewable growth as grid constraints continue to limit utility-scale renewables
How much renewable electricity capacity is South Africa forecast to add by 2031?
- South Africa is forecast to add 29 GW of renewable capacity over 2026–2031, representing a 122% acceleration compared with the 2019–2025 period.
- Annual renewable capacity additions reached almost 3 GW in 2025, 46% above the 2024 level, and are forecast to average almost 5 GW per year over 2026–2031.
- Over 2026–2031, solar PV is set to provide 83% of South Africa’s renewable capacity additions, with wind contributing 17% and bioenergy less than 1%.
Has the IEA revised its renewable electricity forecast for South Africa compared to last year?
Summary: South Africa’s renewable capacity forecast is revised down by 6% compared with last year's edition, with diverging trends across utility-scale capacity and distributed PV. Notable downward revisions include utility-scale solar PV (−25%), onshore wind (−1%) while distributed solar PV (+89%) is revised up significantly.
Solar PV: The solar PV forecast is 7% lower, masking diverging trends across market segments. Utility-scale solar PV is revised downwards due to delayed auction rounds of the Renewable Energy Independent Power Producer Procurement Programme (REIPPPP) and persistent grid constraints. By contrast, distributed solar PV is revised upwards, reflecting stronger-than-expected deployment following the 2022 deregulation of embedded generation, rising electricity tariffs and demand from commercial and industrial consumers seeking more reliable power supply. Historical data are also revised upwards to capture stronger deployment during peak load-shedding and improve coverage of off-grid and residential systems. However, distributed solar PV growth is forecast to moderate as supply reliability improves, load-shedding declines, and NERSA’s net-billing framework and the shift towards fixed tariff charges weaken incentives for residential systems.
Onshore wind: The onshore wind forecast remains constrained by limited grid-connection capacity in the Eastern and Western Cape, where South Africa’s best wind resources are located. As a result, no wind projects were awarded in REIPPPP Bid Windows 6 and 7, limiting near-term deployment despite a strong project pipeline.
What is driving renewable capacity growth in South Africa?
Target and planning framework: South Africa’s updated Integrated Resource Plan 2025 provides a long-term pathway for energy security and decarbonisation through renewable deployment, storage, transmission investment and a gradual reduction in coal dependence. It targets 25 GW of solar PV, 34 GW of wind, 16 GW of distributed generation and 8.5 GW of energy storage additions over 2025–2039, alongside a net-zero power sector by 2050.
REIPPPP auctions: REIPPPP remains the main procurement mechanism for utility-scale renewables. Grid constraints in high-wind-resource areas led Bid Window 7 to award almost 3.9 GW of solar PV but no wind capacity, despite an initial 3.2 GW wind target. The timing and design of Bid Window 8 remain uncertain.
Regulatory reforms: The 2022 amendments to the Electricity Regulation Act removed licensing requirements for private generation projects, accelerating self-generation and distributed solar PV investment. Deployment has since been supported by strong commercial and industrial demand and rising solar PV imports, although imports have moderated since 2024 as supply reliability improved and a 10% duty on solar PV modules was introduced. The planned launch of the South African Wholesale Electricity Market in late 2026 is expected to increase competition, although bilateral contracts are likely to remain the main route to market in the near term.
Distributed solar PV and corporate procurement: A history of load-shedding, rising electricity tariffs, delayed utility-scale procurement and embedded-generation reforms have accelerated distributed solar PV deployment, particularly among commercial and industrial consumers. Corporate PPAs and Eskom wheeling arrangements also support rapid growth in captive and off-site renewable supply, especially in the mining sector.
Transmission expansion: Grid investment is increasingly critical to renewable deployment. Eskom’s Transmission Development Plan 2025–2034 aims to integrate 56 GW of new generation capacity, requiring around 14 000 km of new transmission lines. The Independent Transmission Infrastructure Procurement Programme (ITIPP) is expected to support delivery through private-sector participation in transmission development.
Accelerating battery storage deployment: The first utility-scale storage projects awarded under the Battery Energy Storage Independent Power Producer Procurement Programme (BESIPPPP) are forecast to enter commercial operation by late 2026, adding 360 MW/1 440 MWh of storage. Falling battery costs are also strengthening the economics of solar-plus-storage systems, particularly for commercial and industrial consumers seeking more reliable supply and lower exposure to peak tariffs and load-shedding.
What are the main challenges to renewable capacity growth in South Africa?
Grid capacity constraints: Transmission constraints remain the main barrier to renewable deployment. Limited connection capacity in the Eastern and Western Cape restricts new wind development and prevented wind projects from securing awards in recent REIPPPP rounds.
Uncertain procurement timelines: Procurement delays and limited visibility over future REIPPPP rounds continue to disrupt project pipelines. The timing and design of Bid Window 8 remain key uncertainties.
Policy and regulatory implementation: Although recent reforms have enabled greater private-sector investment, uneven implementation of licensing, wheeling and distributed-generation rules across jurisdictions continues to create uncertainty and delay projects.
Project bankability and financing: High development and grid-connection costs, alongside intense auction competition, have weakened project economics and delayed financial close for some utility-scale projects. Eskom’s financial challenges weigh on infrastructure investment, while limited financing access and currency-driven equipment cost fluctuations constrain distributed solar PV. For residential consumers, high upfront costs and limited access to loans remain significant barriers, particularly for low- and middle-income households.
What would it take for South Africa to achieve the IEA accelerated forecast?
In the accelerated case, South Africa’s renewable capacity additions could be 38% higher than in the main case. Solar PV offers the largest upside potential, followed by onshore wind.
Faster grid expansion: Accelerating transmission investment under the Transmission Development Plan 2025–2034 and ITIPP would unlock connection capacity for wind and utility-scale solar PV, particularly in the Eastern and Western Cape.
Resuming and scaling IPP procurement: Timely launch and delivery of REIPPPP Bid Window 8 would improve project visibility and accelerate solar PV and wind deployment.
Consistent national policy implementation: More consistent implementation of licensing, wheeling and distributed-generation rules would reduce project risks and support investment.
Faster battery deployment: Accelerating utility-scale battery projects and establishing clear frameworks for behind-the-meter storage would increase system flexibility and strengthen the economics of utility-scale and distributed renewables.
A 2 GW utility-scale pipeline to 2027 underpins Azerbaijan’s renewable growth, but delivery depends on bilateral agreements and grid build-out
How much renewable electricity capacity is Azerbaijan forecast to add by 2031?
- Azerbaijan is forecast to add almost 8 GW of renewable capacity over 2026–2031, almost ten times more than in 2020–2025.
- Annual additions more than doubled year-on-year to over 0.3 GW in 2025 and are expected to average over 1 GW per year over 2026–2031.
- Solar PV accounts for almost three quarters (73%) of additions over 2026–2031, followed by wind (25%) and hydropower (2%).
Has the IEA revised its renewable electricity forecast for Azerbaijan compared to last year?
Summary: Azerbaijan’s renewable capacity forecast is revised up by 26% from last year, with upward revisions across all technologies: wind (+14%), solar PV (+31%) and hydropower (+8%).
Solar PV and wind: The upward revision reflects stronger project realisation, as several projects have progressed from planning or agreement stages to construction and commissioning. Key projects include the 100 MW Lake Boyukshor floating solar PV plant and the 240 MW Khizi-Absheron wind project.
What is driving renewable capacity growth in Azerbaijan?
Target: In October 2025, Azerbaijan raised its target for the renewable share of installed capacity from 30% to 38%.
Grid infrastructure expansion: Transmission upgrades are supporting renewable integration. The World Bank’s Azerbaijan Scaling-Up Renewable Energy (AZURE) Project supports network reinforcement, the connection of the 240 MW Absheron-Garadagh wind plant and the integration of up to 1.8 GW of renewable capacity. Grid planning for 2030 and beyond is also being strengthened through co-operation with the China Electric Power Planning and Engineering Institute (EPPEI).
Battery storage: Azerbaijan is pairing renewable expansion with storage. Planned deployment of 250 MW/500 MWh of batteries is expected to support the integration of around 2 GW of renewable capacity.
Foreign investment: Domestic and international partners continue to drive utility-scale renewable projects. The first phase of the green energy development programme includes more than USD 2.7 billion of investment and over 2 GW of projects expected by 2027.
What are the main challenges to renewable capacity growth in Azerbaijan?
Limited open procurement: Competitive procurement remains at an early stage. The 100 MW Gobustan solar PV plant is Azerbaijan’s first auction-based renewable project, and no further auction rounds have been announced. Most projects continue to rely on bilateral PPAs.
Grid and system integration constraints: Grid and storage infrastructure will need to keep pace with the growing project pipeline, as delays in network upgrades could slow project delivery and renewable integration.
Project delivery risks: Although Azerbaijan has a visible project pipeline, timely implementation of signed agreements remains critical to achieving the forecast. This requires continued progress on land allocation, transmission infrastructure, storage and project execution.
What would it take for Azerbaijan to achieve the IEA accelerated forecast?
In the accelerated case, Azerbaijan’s renewable capacity additions are around 45% higher than in the main case. Solar PV offers the largest upside, followed by wind and hydropower, if the challenges are addressed in a timely manner.
Earlier progress in offshore wind: Offshore wind is unlikely to contribute significantly to near-term additions in the main case. However, if the ongoing LiDAR assessment in the Caspian Sea leads to timely project structuring and investment decisions, an initial pilot phase could add a small amount of capacity within the forecast period.
Solar PV boom lifts Uzbekistan’s additions above 3 GW in 2025, but grid upgrades are needed to integrate 25 GW of planned renewables
How much renewable electricity capacity is Uzbekistan forecast to add by 2031?
- Uzbekistan is forecast to add more than 14 GW of renewable capacity over 2026–2031, 78% more than in 2020–2025.
- Annual additions reached over 3 GW in 2025, similar to the 2024 level, but are expected to average around 2.4 GW per year over 2026–2031.
- Solar PV accounts for about three-quarters (75%) of additions over 2026–2031, followed by onshore wind (20%) and hydropower (6%).
Has the IEA revised its renewable electricity forecast for Uzbekistan compared to last year?
Summary: Uzbekistan’s renewable capacity forecast is revised up by almost 70% from last year, with diverging trends across technologies. Solar PV (+126%) and hydropower (+13%) are revised up, while onshore wind (−5%) is revised down slightly.
Distributed solar PV: The forecast is revised up sharply owing to faster-than-expected distributed PV deployment. Around 1 GW of small-scale solar PV was installed in 2025, bringing total solar PV capacity additions to above 2 GW by year-end.
What is driving renewable capacity growth in Uzbekistan?
Target: Uzbekistan aims to reach 25 GW of renewable energy capacity by 2030, supporting its goal of increasing the share of renewable energy to 54% by 2030.
Implementation focus: The policy emphasis has shifted from launching new reforms to accelerating implementation, prioritising project delivery, financing and institutional co-ordination.
Distributed solar PV support: State-backed remuneration for surplus electricity exported to the grid supports rooftop solar PV uptake among households and small businesses.
Storage and system integration investment: Uzbekistan is rapidly expanding energy storage alongside renewables. More than 1.2 GW of energy storage capacity was commissioned in 2025, supporting the integration of rising solar PV and wind generation.
Foreign investment and public-private partnerships: Continued foreign investment and public-private partnerships across generation, storage and network infrastructure are underpinning rapid renewable deployment.
What are the main challenges to renewable capacity growth in Uzbekistan?
Grid and network constraints: Network expansion and grid modernisation need to keep pace with rapid renewable deployment to avoid project delays.
Land allocation and approvals: Delays in land allocation and approval procedures continue to slow project development.
What would it take for Uzbekistan to achieve the IEA accelerated forecast?
In the accelerated case, Uzbekistan’s renewable capacity additions are around 40% higher than in the main case. Solar PV offers the largest upside, followed by wind and hydropower.
Faster grid upgrades: Accelerating transmission and distribution upgrades would improve the integration of renewables, storage and growing electricity demand, enabling higher deployment.
Sustained distributed solar PV growth: Maintaining the recent pace of rooftop solar PV deployment, supported by small-scale incentives and strong demand from households and businesses, would further increase additions.
More flexibility from batteries and hydropower: Faster battery deployment and timely hydropower additions would strengthen system flexibility, enabling additional solar PV and wind capacity.
Stronger project delivery in 2025 and new procurement rounds improve Russia’s renewable outlook
How much renewable electricity capacity is Russia forecast to add by 2031?
- Russia is forecast to add around 5 GW of new renewable capacity over 2026–2031, representing a 17% decrease compared with the 2020–2025 period.
- Annual additions rose by around 0.8 GW in 2025, similar to the 2024 level and are expected to average below 1 GW per year over 2026–2031.
- Solar PV accounts for 42% of additions over 2026–2031, followed by wind at 40%, with hydropower making up the remainder.
Has the IEA revised its renewable electricity forecast for Russia compared to last year?
Summary: Russia’s renewable capacity forecast is revised up by 30% from last year, with diverging trends across technologies. Hydropower (+159%), Wind (+52%) and solar PV (+11%) are revised up, reflecting stronger-than-expected commissioning in 2025 and a firmer near-term outlook for 2026, while biomass (−99%) is revised down.
Planning framework: Russia’s latest Scheme and Programme for the Development of Electric Power Systems (S&PR) 2026–2031 includes higher renewable capacity assumptions than the previous S&PR 2025–2030.
What is driving renewable capacity growth in Russia?
State-backed support mechanisms: Renewable deployment continues to rely on state support. The wholesale-market support programme remains the main driver of utility-scale projects through long-term capacity payments, while separate retail-market and isolated-system mechanisms support smaller projects.
Far East procurement: Additional procurement in the Russian Far East is supporting deployment. In 2025, a dedicated round selected 45 projects totalling around 1.6 GW, including more than 1 GW of solar PV and over 500 MW of wind.
Long-term policy continuity: The government has extended its renewable support framework to 2035, improving long-term visibility for project development. More than 12 GW of renewable capacity is expected to be added by 2035 under the updated framework.
What are the main challenges to renewable capacity growth in Russia?
Broad-based capacity planning: The latest S&PR 2026–2031 raises thermal and nuclear capacity assumptions alongside renewables, indicating that renewables are expanding as part of a broader capacity build-out rather than a dedicated decarbonisation push.
High financing costs and project risks: High lending rates and sanctions-related risks raise financing costs and weaken project economics.
Weak incentives: Low wholesale electricity prices weaken the economic case for unsubsidised renewable investment.
What would it take for Russia to achieve the IEA accelerated forecast?
In the accelerated case, Russia’s renewable capacity additions are around 41% higher than in the main case. Solar PV offers the largest upside, followed by wind and earlier deployment of hydropower.
Continued policy support through 2035: Achieving the accelerated case would require sustained state support into the 2030s.
Global liquid biofuel demand expands nearly 30% by 2031
Global liquid biofuel demand is forecast to rise from 198 billion litres (5 EJ; 3 401 kb/d) in 2025 to 251 billion litres (6.6 EJ; 4 331 kb/d) in 2031 in the main case. Stronger blending mandates and policy support underpin this expansion, as countries seek to strengthen energy security, reduce oil import dependence and cut transport emissions.
Road transport accounts for nearly 85% of demand growth. Brazil and India lead ethanol expansion. Brazil has raised its ethanol blending requirement from 30% to 32% to strengthen energy security and reduce exposure to elevated gasoline prices amid the conflict in the Middle East, while India has achieved its 20% ethanol blending target five years ahead of schedule. In the United States, higher fuel volume obligations under the Renewable Fuel Standard (RFS) drive renewable diesel growth. Biodiesel demand grows in Indonesia through its 40% blending mandate and rising overall fuel consumption, and in Brazil through gradual increases in biodiesel blending. In Canada and Europe, requirements to reduce transport fuels’ greenhouse gas (GHG) intensity support further demand for all three fuels, with liquid biofuel blending remaining a key route to compliance.
Aviation and maritime transport make up the remaining roughly 15%. Demand for SAF continues to grow, driven primarily by the ReFuelEU Aviation regulations, which entail 6% SAF by 2030, and the UK SAF mandate requiring 10% by 2030. Mandates, supply-side obligations, and indicative and emissions-reduction-based targets in several other countries such as Brazil, Japan, Singapore, India, Malaysia, Indonesia and Korea also drive demand globally. Meanwhile, demand for marine biodiesel stems primarily from the EU FuelEU Maritime requirements to reduce ships’ well-to-wake GHG intensity by 6% by 2030 and 14.5% by 2035, as it is one of the few commercially available low-emissions fuels. Demand in the Asia Pacific region also rises because the region services ships headed for Europe.
In the accelerated case, full implementation of announced targets and mandates could lift liquid biofuel demand to 333 billion litres (9.0 EJ; 5 740 kb/d) by 2031, nearly 35% above the main case. One-third of this additional growth stems from continued support for higher ethanol blends in the United States, Brazil and India, while biodiesel and renewable diesel each contribute roughly 20% of this growth through continued US RFS fuel obligations and higher biodiesel blending in Southeast Asia. Additional growth results from further implementation of SAF mandates in several regions, and from potential implementation of the International Maritime Organization (IMO) Net-Zero Framework (voting was delayed from 2025 to December 2026). However, achieving this would require additional investment in production capacity and distribution infrastructure, alongside affordable, sustainable feedstock supplies.
Energy security and affordability concerns due to the recent conflict in the Middle East drive liquid biofuel growth in the main case. Higher gasoline prices have prompted Brazil to accelerate the implementation of blending increases envisaged under its Fuel of the Future Law, raising mandatory ethanol blending from 30% to 32%. Demand for biodiesel increases as blending mandates are raised further, and demand for biojet fuel is driven by emissions-reduction requirements in aviation beginning in 2027 under the Fuel of the Future Law.
Full implementation of the Fuel of the Future Law would unlock further growth in the accelerated case, creating stronger demand across ethanol, biodiesel and renewable diesel. Higher mandated blends—35% ethanol in gasoline, 20% biodiesel and 3% renewable diesel—expand the market for these fuels, while aviation emissions-reduction requirements support biojet fuel use. Realising this potential requires production capacity and sustainable feedstock supplies to keep pace with policy ambitions.
India’s ethanol blending programme continues to support liquid biofuel growth in the main case after the country achieved its 20% target in 2025, five years ahead of schedule. With blending maintained at this level, rising fuel consumption drives further ethanol use, supported by continued development of the supply chain, while biodiesel expansion remains limited by feedstock availability. In aviation, the indicative 5% SAF target for 2030 and investment in biojet production, including alcohol-to-jet facilities, support an emerging market and drive initial progress towards this target in the main case.
Further efforts to reduce crude oil imports support higher blending in the accelerated case, while stronger policy enables India to meet its 5% biodiesel and indicative SAF targets by 2030. Delivering this growth requires faster production development and progress in overcoming the feedstock constraints that limit biodiesel uptake in the main case.
Higher fuel volume obligations under the federal Renewable Fuel Standard (RFS) underpin US growth in the main case, primarily by increasing demand for renewable diesel. Federal and state policies and incentives also support biojet fuel use. Demand for ethanol grows as summer waivers have allowed sales of 15% blends, but limited availability of suitable storage and distribution infrastructure at fuel stations restricts wider uptake.
Overcoming these infrastructure barriers and sustaining policy support would enable further growth in the accelerated case. Continued increases in RFS fuel obligations provide a stronger demand signal for biodiesel and renewable diesel, while permanent nationwide E15 availability opens a larger market for ethanol. Retail infrastructure upgrades are essential to turn this wider market access into fuel sales. Continued support under the Clean Fuel Production Tax Credit and deployment of new production technologies, particularly for biojet fuel, help expand supply to meet additional demand.
Canada’s Clean Fuel Regulations, supported by provincial blending mandates and low-carbon fuel standards, drive demand for liquid biofuels in road transport as the regulations require reductions in the carbon intensity of liquid transport fuels. The province of British Columbia’s 3% SAF blending mandate for 2030 also creates a small amount of initial demand for biojet fuel.
Building on this emerging aviation market, the accelerated case assumes Canada advances recommendations under its national SAF Blueprint to strengthen support for SAF development. This complements the federal and provincial policies already supporting liquid biofuels in road transport.
Indonesia’s efforts to reduce fossil fuel imports drive liquid biofuel growth in the main case with continued implementation of its 40% biodiesel blending mandate amid additional overall fuel demand. However, production capacity constraints prevent further increases in blending despite the announced 50% ambition. Ethanol, renewable diesel and SAF targets provide additional demand signals, but uptake remains below announced ambitions because of likely competition for feedstocks between oil-based liquid biofuels and the need for further production capacity.
Addressing these challenges through faster supply and capacity expansion allows Indonesia to make greater progress towards its blending ambitions in the accelerated case. Biodiesel blending rises to 45%, still below the 50% target, while greater progress is made towards announced ethanol and renewable diesel targets. The SAF target is met, as it remains relatively low. Meeting this demand requires further access to sustainable feedstocks and additional production capacity to be developed faster than in the main case.
Europe’s liquid biofuel demand in the main case is driven by implementation of RED III through stronger national emissions-reduction obligations and advanced biofuel requirements. Dedicated aviation and shipping regulations drive demand for liquid biofuels beyond road transport. ReFuelEU Aviation and the UK SAF mandate require SAF shares of 6% and 10%, respectively, by 2030, while FuelEU Maritime drives demand for marine biodiesel through ships’ well-to-wake emissions-reduction requirements.
Meeting this policy-driven demand also requires supply to expand. In the accelerated case, continued implementation of RED III is complemented by stronger support for new and emerging production technologies. Programmes such as Horizon Europe and the Sustainable Transport Investment Plan help expand renewable fuel supply to meet policy-driven demand. Faster technology deployment supports delivery of transport fuel obligations and aviation and maritime requirements, with supply development playing a central role in realising the additional growth.
Heat accounts for around half of global final energy consumption and is the largest source of energy-related CO2 emissions. As electrification and renewable heat technologies expand, modern renewables rise from 15% of global heat demand in 2025 to 19% in 2031. Over the same period, total heat-related CO2 emissions fall roughly 4%. Direct emissions from burning fuel stay broadly unchanged, but indirect emissions decline as cleaner power lowers the carbon intensity of electricity used for heat.
Electrification becomes the main source of growth. Renewable electricity used for heat grows more than 50%, from 9.4 EJ in 2025 to 14.6 EJ in 2031, and provides around two-thirds of the growth in modern renewable heat. Together with ambient heat captured by heat pumps, it accounts for almost three-quarters of the increase. The renewable share of electricity used for heat rises from 35% to around 46%. Ambient heat grows nearly 6% per year, faster than any other direct renewable source. The pace of electrification still depends closely on the price of electricity relative to fossil fuels and on stable policies.
Modern bioenergy, solar thermal and geothermal still supply around 60% of renewable heat in 2025, but they provide only one-quarter of the growth to 2031. Combined, they grow 1.6% per year, compared with more than 7% for heat from renewable electricity. Modern bioenergy, mainly solid biomass, remains the largest renewable heat source and rises from 17.8 EJ to 19.2 EJ. Solar thermal growth slows to around 3.5% per year as China's market matures.
Growth is concentrated in China and the European Union. China delivers more than one-third of global growth, mostly through electrifying industry. The European Union is the second-largest contributor, mainly through electrification in buildings and renewable district heating. By sector:
- Buildings: renewable heat grows 25% and heat-related emissions fall 7%.
- Industry: the renewable share rises from 16% to 19%, but fossil fuels still meet more than 80% of demand.
- Agriculture: fossil fuels still supply almost 90% of heat demand in 2031.
District heating remains the largest untapped opportunity. Networks supplied 17.7 EJ of heat in 2025, around 8% of global heat demand, but less than 7% came from renewables, and this share stays broadly unchanged to 2031. China and Russia account for around four-fifths of the world's fossil-fuelled district heat; EU-like renewable shares in both would add around 6 EJ of renewable district heat. Meanwhile, the traditional use of biomass falls from 18.7 EJ to 16.7 EJ, but clean cooking remains a major challenge, especially in Sub‑Saharan Africa.
China delivers more than one-third of global renewable heat growth to 2031, driven almost entirely by electrification. In industry, renewable heat use rises 1.9 EJ between 2025 and 2031, lifting its share of industrial heat demand from 8% to 12%. Renewable electricity provides nearly all of this growth: the renewable share of electricity used for industrial heat rises from 37% to almost 50%. Connecting factories directly to their own solar and wind plants, often with thermal storage, could nearly halve the cost of electrified steam.
In buildings, renewable heat rises 1.1 EJ, and the renewable share grows from 20% to 27%. Renewable electricity provides two-thirds of the increase. Ambient heat grows roughly 7% per year, supported by the 2025 national heat pump action plan and appliance trade-in subsidies. China accounts for around two-thirds of global solar thermal use, but growth slows to around 2% per year as heat pump water heaters take over more of the residential water-heating market. The 15th Five-Year Plan's Renewable Energy Development Plan for 2026‑2030 aims for a 2.5-fold increase in renewable energy use outside the power sector by 2030, including renewable heat.
China shows that expanding district heating networks does not by itself guarantee decarbonisation. Its 9.3 EJ network gets less than 5% of its supply from renewables, and that share falls slightly as fossil-fired capacity grows faster than renewable alternatives. If China reached EU-level renewable shares, global renewable district heat would increase by almost 4 EJ by 2031. That is more than three times today's worldwide renewable district heat supply. China also cuts its traditional use of biomass by almost 90% between 2010 and 2031.
The European Union is the second-largest contributor to global renewable heat growth. In buildings, it records the biggest rise in renewable share among major heat markets. Renewable heat in buildings grows 0.9 EJ to 2031, and the renewable share rises from 34% to 42%, mainly through renewable electricity and heat pumps. Ambient heat from heat pumps grows 7.4% per year, the fastest among major markets. European heat pump sales recovered in 2025, rising 13% to 2.9 million units after three years of decline. RED III, the Energy Performance of Buildings Directive, the Energy Efficiency Directive and ETS2 all strengthen the policy framework, although grant schemes increasingly differ across member states.
The European Union delivers almost all global growth in renewable district heating. Renewables supplied around 35% of EU district heat in 2025, and this is set to reach around 42% by 2031. The growth comes from bioenergy, large-scale heat pumps, solar thermal, geothermal and waste heat recovery. In industry, renewable heat grows 330 PJ, raising its share of industrial heat demand from 25% to 29%. Renewable electricity provides over 80% of this growth, as the renewable share of electricity used for industrial heat rises from 48% to 64%.
The July 2026 Electrification Action Plan targets the gap between electricity and gas prices. It recommends that by 2030 electricity cost no more than 2.5 times as much as gas for households and 2.0 times for industry, and it aims for 4 million heat pump installations per year by 2030. The Innovation Fund's first Heat Auction selected 65 projects worth nearly EUR 400 million, and a second EUR 1 billion round is due to open in December 2026.
The United States has the slowest renewable heat growth among major markets, even though heat pump adoption continues. Renewable heat in buildings grows by only 276 PJ to 2031, or 2.2% per year. Ambient heat accounts for around 60% of that increase. The United States remains the largest heat pump market, and heat pumps outsold gas furnaces for a fourth consecutive year in 2025. However, federal 25C and 25D tax credits expired after 2025, and updated HUD and USDA building code requirements were rescinded. This makes state-level measures more important, including building electrification requirements, carbon pricing and rebate programmes.
In industry, renewable heat use grows just 94 PJ by 2031, and the renewable share stays flat at around 17%. Federal support has weakened, including the cancellation of more than half of the projects selected under the Industrial Demonstrations Program. Industrial thermal storage nevertheless continues to advance where low-cost electricity or tailored tariffs improve project economics. Examples include large heat battery projects in California and South Dakota.
India is the largest consumer of direct renewable heat in industry and accounts for one-quarter of global growth in industrial renewable heat to 2031. Renewable heat in industry increases by 1.0 EJ, with bioenergy providing two-thirds of the growth. This is concentrated in agro-industrial sectors such as sugar, pulp and paper, and rice processing, where bagasse, black liquor and rice husks provide low-cost process heat. Electrification advances more gradually: electricity's share of industrial heat demand rises from 7% in 2025 to 9% in 2031.
India also records the largest increase in industrial solar thermal, providing over half of global growth. In buildings, renewable heat grows 50%, the fastest among major emerging economies, helped by solar water-heating requirements in building codes and state mandates. The National Bioenergy Programme and the GOBARdhan scheme, which runs to FY 2035‑36, support biomass supply chains and biogas.
India's progress is critical for clean cooking. Traditional biomass use falls from 4.3 EJ to 3.3 EJ by 2031 as access to liquefied petroleum gas (LPG) expands. However, cost still keeps many households from fully moving away from firewood.
Global production of biogases (both biogas and its purified stream, biomethane) reached 1 785 PJ in 2025, of which 78% was biogas. Production continues to increase in most countries/regions, with global output forecast to grow 18% over 2026-2031 in the main case and 35% in the accelerated case.