Written by James McCatherin, Business Development Partner, Offshore Wind Academy
APAC offshore wind is not a single market. Mainland China operates at a scale that dwarfs the rest of the region, but does so within its own ecosystem of developers, OEMs, and supply chains. Beyond China, the region contains several markets at varying stages of maturity. This piece focuses on the four with the most active development today: Taiwan, Japan, Korea, and Australia. Each operates under different technical conditions, regulatory frameworks, and commercial realities.
What makes 2026 unusual is that all four are being restructured at the same time, in different directions, for different reasons. Taiwan is dismantling its localization regime. Japan is redesigning its auction framework after its flagship projects were withdrawn. Korea has overhauled its permitting law but is contending with project-level execution problems. Australia is still writing the rules through its first major projects.
Taiwan: The Localization Era is Ending
Of the four markets, Taiwan is the most mature and remains the largest by installed capacity, with 4.5 GW from 482 turbines as of March 2026. Technical conditions are demanding with frequent typhoons, seismic activity, and a Taiwan Strait seabed that combines mobile sediments, soft clays over harder layers, and localized geohazards. Taiwan’s shallow-water fixed-bottom area is also approaching saturation, which is why the government’s emerging floating offshore wind framework matters for future capacity.
The earlier-generation projects awarded under Taiwan’s Round 2 framework have largely delivered. Greater Changhua 2b and 4 has all 66 turbines installed and is targeting full commercial operation in Q3 2026. The 1 GW Hai Long project achieved first power in June 2025, has more than two-thirds of its 73 turbines installed as of mid-2026, and signed an expanded long-term CPPA with TSMC in April 2026. The market has demonstrated it can build.
Round 3.1 and 3.2, awarded under tightened localization rules, have been a different story. Round 3.1, awarded in December 2022, saw movement from award to construction stall across the cohort. CIP’s Fengmiao was the only 3.1 project to reach financial close, and that came more than two years after award. Round 3.2, awarded in August 2024, has fared worse: of the five projects allocated 2.7 GW, two had their development rights withdrawn by the MOEA by June 2025, and the remaining projects are generally stalled.
Combined with sustained pressure from the European Union, including a WTO dispute, this prompted a regulatory reset. For Round 3.3, the Ministry of Economic Affairs has removed the strict 27-item localization regime. The selection mechanism now weights developer track record, financial strength, and project execution capability, with ESG and energy resilience factors integrated into the evaluation. A floor price of TWD 2.29 per kWh has been introduced to support project financing. Applications opened on 1 April 2026 and run through 30 September, with 3.6 GW on offer; results are expected by the end of the year. There is cautious optimism that Round 3.3 will help move forward a market that had stalled under the previous rules, but results remain to be seen.
Japan: After Round 1, a Market Being Rebuilt
Japan shares Taiwan’s exposure to typhoons and seismic activity, but bathymetry that drops off rapidly close to shore makes floating offshore wind essential to the long-term opportunity, not optional. The EEZ Law passed by the Diet in June 2025 unlocks development beyond Japan’s 12-nautical-mile territorial waters for the first time, expanding the addressable area for floating projects.
The defining event of 2025 was the formal withdrawal in August by the Mitsubishi-led consortium from approximately 1.7 GW of Round 1 projects across Akita and Chiba prefectures. These were the projects expected to be Japan’s first large-scale offshore wind farms to reach commercial operation. The consortium cited construction costs more than doubling, turbine prices doubling, and unfavorable foreign exchange and interest rate movements relative to the aggressive 2021 bid prices that had left limited inflation buffers. JPY 20 billion in security deposits were forfeited, a scale of withdrawal highly unusual for a leading Japanese trading house.
The government’s policy response has moved on two tracks. First, the November 2025 METI/MLIT package “Measures to Ensure the Successful Completion of Offshore Wind Projects” set out seven reforms targeting the delivery of Round 2 and Round 3 projects, including revised evaluation criteria for future auctions across price, execution capability, and committed commercial operation dates. Second, at the second Study Group on Port Infrastructure in January 2026, MLIT presented five operational improvements to base port leasing arrangements, designed to reduce project finance uncertainty and encourage private investment in port upgrades for the floating wind era. Round 4, originally expected in 2025, has not yet been held.
Delivery has continued. In January 2026, the 16.8 MW Goto floating wind farm entered commercial operation, becoming Japan’s first commercial floating offshore wind farm and the world’s first commercial application of hybrid SPAR-type floater technology. Goto is small, but floating is central to Japan’s long-term capacity given how rapidly coastal waters deepen. In March 2026, the 220 MW Kitakyushu Hibikinada wind farm in Fukuoka Prefecture entered commercial operation, becoming Japan’s largest offshore wind farm to date.
Korea: Policy Reform & Project Headwinds
Korea faces the least demanding technical conditions among the four markets. Typhoon exposure is limited compared with Taiwan and Japan, seismic activity is modest, and seabed conditions on the south and west coasts are generally workable. Ulsan is developing as a hub for floating offshore wind, with multiple projects sharing access to a contracted 6 GW transmission system.
The regulatory framework has been transformed. The Offshore Wind Promotion Act, passed by the National Assembly on 27 February 2025, replaces the previous developer-led “open-door” model with a government-led system. Under the old model, projects required permits across ten ministries and 29 laws; under the new Act, the government designates project zones and consolidates approvals into a streamlined process. Average permitting timelines are targeted to fall from approximately ten years to roughly three. The administration of President Lee Jae-myung, elected in June 2025, has continued and accelerated implementation, with a national target of 20 GW by 2030.
At the project level, the picture is more mixed. The H1 2025 auction awarded 689 MW entirely to state-affiliated developers, with all private bidders, including CIP and B Grimm, unsuccessful.
Individual projects have run into specific problems. The 532 MW Anma project, awarded in the 2024 auction, has been delayed by an overlap between the project site and a maritime area used by the Agency for Defense Development for weapons testing; shareholder Equis is now reportedly looking to sell its 78% stake. Equinor’s 750 MW Bandibuli/Firefly floating project off Ulsan failed to sign its REC offtake contract by the September 2025 deadline and is temporarily on hold. BadaEnergy, the SPC for the 1.5 GW Gray Whale floating project, has begun liquidation.
At the market level, Corio Generation withdrew from Korea in early 2026, RWE has exited two projects, Shell has left MunmuBaram, and Equinor withdrew from a Jeju project after the province introduced significant local benefit-sharing requirements.
Korea’s policy framework is moving faster than its underlying project base. The new regime is designed to address exactly these execution challenges; how well it does so will become clearer as the new auctions and zone designations roll out.
Australia: New Sector, Slow Build
Australia faces a different technical environment from its APAC peers. There are no typhoons and negligible seismic activity, but Southern Ocean conditions present their own design challenges including Bass Strait swell, the wind regime of the Roaring Forties, and significant currents. The technical baseline is closer to the United Kingdom’s deeper-water sites than to Taiwan or Japan.
Australia’s regulatory framework is the youngest of the four markets. Six offshore wind zones have been declared nationally, but developer interest has varied across them.
Gippsland in Victoria has attracted the most interest. Twelve feasibility licenses were originally awarded from 37 applications; three have been surrendered since mid-2025 (BlueFloat Energy, RWE, and the AGL-led Gippsland Skies consortium), leaving nine active. The Bunbury zone in Western Australia had its first feasibility licenses awarded in January 2026. The Illawarra (NSW) and Bass Strait Tasmania zones did not attract sufficient interest to proceed.
Victoria has legislated targets of 2 GW by 2032, 4 GW by 2035, and 9 GW by 2040, with VicGrid coordinating shared transmission for the Gippsland precinct. No project has yet reached final investment decision anywhere in Australia; the binding constraints have been federal-state coordination, environmental assessment, grid connection planning, and Indigenous engagement.
Star of the South, located in Bass Strait approximately 10 km off the Gippsland coast, is the most advanced project. It released its draft Environmental Impact Statement on 18 May 2026, with public submissions closing on 29 June. The Australian Industry Participation plan filed for the project discloses capital expenditure of approximately AUD 11 billion for an installed capacity of up to 2.2 GW. Southerly Ten’s separate Kut-Wut Brataualung project, named in consultation with the Gunaikurnai Land and Waters Aboriginal Corporation as the Registered Aboriginal Party for the area, is an early example of traditional owner engagement in Australian offshore wind.
Australia’s offshore wind sector is genuinely new. The rules are being defined as the first projects move through them.
APAC: A Region in Motion
APAC remains one of the most exciting regions in global offshore wind. The combined ambition across Taiwan, Japan, Korea and Australia adds up to tens of gigawatts of planned capacity, but the headwinds are similar across the region: cost inflation, supply chain pressure, financing risk, and local opposition.
2026 is a year of change. The rules being written this year, how industry reacts to them, and further development of macro trends will shape what gets built across APAC in the next decade.
Sources
Government announcements from MOEA (Taiwan), METI and MLIT (Japan), MOTIE (Korea), and DCCEEW (Australia); industry analysis from Aegir Insights, DeepWind, IEEFA, and the Renewable Energy Institute; legal commentary from Kim & Chang, Norton Rose Fulbright, and White & Case; and reporting from offshoreWIND.biz, Maritime Executive, Riviera, and RenewEconomy.
James McCatherin is a Business Development Partner with Offshore Wind Academy, with 5 years of Industry experience across the APAC region. His areas of expertise include permitting and policy, markets, and stakeholder engagement.