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From offshore wind zones to new grid infrastructure laws, Asian jurisdictions are reshaping the region’s energy sector

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JAPAN

KOREA

PHILIPPINES

TAIWAN

Japan’s 2026 plan to promote offshore wind energy in EEZ

In Japan, the promotion of renewable energy is expected to continue to advance through groundbreaking amendments that allow offshore wind power projects in Japan’s exclusive economic zone (EEZ) and the strengthening of the Green Transformation (GX) emissions trading system, both of which are set to take effect. The Act on the Development of Marine Renewable Energy Power Generation Facilities (the amended Act on Promoting the Utilisation of Sea Areas), which enables the installation of marine renewable energy power generation facilities in the EEZ is scheduled to come into force on 1 April 2026.

The Act on the Promotion of Smooth Transition to a Decarbonised, Growth-Oriented Economic Structure (GX Promotion Act) has also been amended, and participation in the Emissions Trading System (GX-ETS) will become mandatory for specified companies starting 1 April 2026.

Act opens door to marine development

Under the amended Act on Promoting the Utilisation of Sea Areas, sites available for the installation of marine renewable energy power generation facilities will be expanded from the territorial and inland waters to the EEZ. Significant progress in offshore wind power generation projects is expected, particularly through the development of floating wind turbines.

A two-stage framework has been adopted for permitting the installation of marine renewable energy power generation facilities in the EEZ, unlike the single-stage framework used for territorial and inland waters. The key procedures are outlined below.

Designation of solicitation zones. The Minister of Economy, Trade and Industry (METI Minister) may, following public notice and consultations with administrative authorities, designate certain zones of the EEZ that are appropriate in light of natural conditions and other relevant circumstances as solicitation zones for the installation of marine renewable energy power generation facilities (the Solicitation Zones) (article 32, paragraph 1).

Grant of provisional status (provisional permit). Business operators intending to install marine renewable energy power generation facilities shall identify sea areas within the Solicitation Zones and apply for provisional status, together with a draft of the zone map and a plan for the installation of marine renewable energy power generation facilities (the installation plan) (article 33, paragraphs 1 and 2). Such business operators may obtain provisional status (a provisional permit) only if the METI Minister and the Minister of Land, Infrastructure, Transport and Tourism find that the application complies with the criteria for the supply price, the marine renewable energy power generation facilities, and the methods of maintenance and management of those facilities (article 34, paragraph 1). When applications overlap in the same area of the Solicitation Zones, the business operator deemed most appropriate to enable the long-term, stable and efficient operation of the marine renewable energy power generation project shall be selected (article 34, paragraph 1, item 2). Provisional permits are subject to a validity period of up to five years (article 34, paragraph 2).

While other regulations under the Foreign Exchange and Foreign Trade Act may apply, the amended Act on Promoting the Utilisation of Sea Areas does not directly restrict the participation of foreign companies or foreign capital.

Establishment of council. Following the granting of provisional status, a council must be established to hold the deliberations necessary for the operation of the marine renewable energy power generation business within the Solicitation Zones (article 36, paragraph 1).

If the draft of the zone map or the Installation Plan submitted by the provisionally approved business operator is inconsistent with the results of the above deliberations, the business operator shall revise them to be in compliance with such results (article 36, paragraph 6).

Installation permit. Provisionally approved business operators shall, within the validity period, refine and revise their zone map and the installation plan drafts, and apply for an installation permit, together with a finalised zone map and Installation Plan (article 37, paragraphs 1 and 2).

Provisionally approved business operators may obtain an installation permit only when the application is found to meet certain criteria, including consistency with the particulars on which the council has reached a consensus (article 38, paragraph 1).

Business operators that obtain an installation permit may install marine renewable energy power generation facilities within the permitted area (excluding territorial and inland waters), and are also obliged to maintain, manage and remove the facilities in accordance with the approved Installation Plan (article 38, paragraph 4; article 40). For their business to be eligible for the FIT or FIP systems, they need to participate in bidding under the Act on Special Measures Concerning Procurement of Electricity from Renewable Energy Sources by Electricity Utilities.

GX-ETS emissions reporting and trading

Under the amended GX Promotion Act, a business operator whose annual average carbon dioxide emissions during the preceding three fiscal years reaches 100,000 tons or more shall annually report to the METI Minister the following information:

1. 1. Their name, location and the name of their representative;
   2. Their business sector and activities;
   3. Their annual average CO? emissions;
   4. Their emissions target for the relevant fiscal year and the basis for setting that target; and
   5. Other matters specified by the ordinance (article 33, paragraph 1).

Allocation of emission allowances. When satisfied that the content of the reporting is appropriate in light of the implementation guidelines, the METI Minister shall allocate the emission allowance to the notifying business operators for free, based on the emission quantity target stated in the notification (article 34, paragraph 1). Such business operators shall report their actual emissions for the allocation year to the METI Minister, the Minister of the Environment, and the relevant Minister in charge of the business in the year following the allocation year (article 35, paragraph 1). Such business operators shall obtain confirmation from a registered confirmation body that the actual emissions volume has been appropriately calculated using the calculation method specified in the implementation guidelines (article 35, paragraph 2; Enforcement Order article 5), and attach a report detailing the confirmation results (article 35, paragraph 3; article 33, paragraph 3).

The METI Minister shall notify the business operators who have reported a quantity of emission allowances equivalent to their actual emissions (article 36, paragraph 1). If the content of the report is inappropriate, or if otherwise necessary, the METI Minister shall, based on an investigation, determine the quantity of emission allowances to be held and notify the business operator (article 36, paragraph 2). Such business operators shall then hold the quantity of emission allowances notified pursuant to article 36, paragraph 2 in their holding account by 31 January of the year following the allocation year (the amortisation date) (article 36, paragraph 3). Emission allowances may be traded but speculative trading is not permitted (article 38).

Emissions trading. The emissions allowance trading market (article 111, paragraph 1, item 6(a)) is scheduled to open around autumn 2027. The METI Minister shall, taking into account the impact on industry and people’s lives, the status of transition to GX, and consistency with measures concerning energy supply and demand, determine the reference upper trading price (the price that serves as the basis for calculating the upper limit of the trading price for an emission allowance equivalent to one ton of carbon dioxide) before the start of each fiscal year (article 39, paragraph 1).

Meanwhile, the METI Minister shall, each fiscal year, set the adjusted benchmark trading price before the start of the fiscal year, taking into account the level of the trading price of emission allowances that induce business activities, and domestic and international economic trends concerning carbon dioxide emissions (article 116, paragraphs 1 and 2). The GX Promotion Organisation may purchase emission allowances to adjust its trading price when the average trading price falls below the adjusted benchmark trading price (article 111, paragraph 1, item 7; article 117, paragraph 1).

Amortisation of emission allowances. The METI Minister shall amortise the notified quantity of emission allowances on the amortisation date (article 37, paragraph 1). The METI Minister collects an unamortised equivalent contribution from the business operators who have not received amortisation for the notified quantity of emission allowances from the METI Minister during the relevant allocation year, on or after the day following the amortisation date. This contribution is calculated as the amount obtained by multiplying the quantity of emission allowances for which amortisation has not been received by the notified quantity by the reference upper trading price, then multiplying that amount by 1.1 (article 41, paragraph 1).

Oh-Ebashi LPC & Partners
Nakanoshima Festival Tower 27F, 2-3-18 Nakanoshima
Kita-ku, Osaka 530-0005, Japan
Tel: +81 06 6208 1500
Fax: +81 06 6226 3055
Email: shunta.doki@ohebashi.com

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Anchoring power strategy: South Korea’s 11th Basic Plan

South Korea’s 11th Basic Plan for Electricity Supply and Demand (2024-2038) serves as the policy anchor for the nation’s long-term electricity supply strategy. Finalised in February 2025 together with key statutes pursuant to article 25 of the Electric Utility Act, it provides the regulatory framework guiding Korea’s energy transition.

Transmission infrastructure

It is recognised as a precondition to energy transition. The Special Act on Expansion of the National Power Grid (National Power Grid Act), enacted in March 2025 and effective since September 2025, was introduced to address grid capacity constraints that have emerged as a structural bottleneck in South Korea’s energy transition.

Amid transmission congestion and rapid load growth from electrification and data centres, the government has repositioned grid reinforcement as a prerequisite to achieving generation targets, shifting policy emphasis from capacity expansion alone to transmission adequacy in the country.

The National Power Grid Act establishes a statutory framework for designated transmission projects, enhances inter-agency co-ordination and introduces procedural mechanisms to streamline high-voltage infrastructure development. As a result, transmission and grid capacity are expected to become critical factors in assessing project feasibility.

Offshore wind

The Special Act on the Promotion of Offshore Wind Power Distribution and Industry Development (OWP Promotion Act), enacted in March 2025 and taking effect in March 2026, introduces a government-led, zone-based planning model for offshore wind development.

Although offshore wind remains central to South Korea’s energy transition strategy, project development has frequently encountered structural and procedural inefficiencies including fragmented and decentralised permitting, environmental review complexity, and local stakeholder opposition.

Under the framework established by the OWP Promotion Act, offshore wind zones will be designated through centralised planning with environmental and stakeholder considerations reflected at an earlier stage. Furthermore, project approvals will follow integrated procedures. Its enforcement decree, which is currently under preparation, is expected to provide more detailed measures, including how zones are selected, how developers are appointed, and how grid interconnection is managed.

The restructuring is expected to improve regulatory predictability in offshore wind development, while potentially intensifying competition for participation in government-designated zones.

Nuclear energy waste governance

The Special Act on the Management of High-Level Radioactive Waste (HLRW Act), enacted in March 2025 and effective since September 2025, establishes a statutory framework governing institutional responsibility and procedural standards for the management of high-level radioactive waste.

While the 11th Basic Plan confirms nuclear energy as part of South Korea’s future energy generation mix, recognising it as a stable source of carbon-free baseload capacity, the sustainability of nuclear operations depends on the credible management of high-level radioactive waste.

The HLRW Act seeks to address this structural dependency by formalising the allocation of responsibilities and codifying procedural standards applicable to waste management, thereby establishing a stable foundation necessary for the continued participation of nuclear power in Korea’s energy system.

Distributed energy

The Special Act on Promotion of Distributed Energy (Distributed Energy Act), effective since June 2024, supports localised and distributed energy generation. By introducing grid impact assessment mechanisms to evaluate how new projects affect system stability, it promotes distributed resources while integrating them into grid planning.

Together with the 11th Basic Plan, localised and distributed energy generation complements transmission expansion by alleviating network congestion and enhancing overall system flexibility.

Hydrogen

The Hydrogen Economy Promotion and Hydrogen Safety Management Act (Hydrogen Act), effective since October 2025, provides the statutory basis for hydrogen production and safety regulation. Hydrogen’s role in power generation remains cost-dependent, but the act establishes its legislative foundation.

From blueprint to execution

The 11th Basic Plan marks a transition from policy declaration to legislative execution. Rather than remaining a strategic blueprint, the plan is being reinforced by a series of targeted special statutes that embed its priorities into binding regulatory structures.

The Korean government’s policy stance has shifted decisively toward the practical execution of the energy transition, rather than focusing on the energy targets it wishes to achieve.

While establishing a fundamental foundation for the overall transition by reforming transmission and grid systems, the government aims to expedite offshore wind development through government-led zoning, simultaneously promoting localised and distributed energy to alleviate grid congestion.

Furthermore, by providing guidance on nuclear waste management, it ensures that nuclear power continues to play a solid role as a reliable carbon-free energy source.

For investors and market participants, these shifts emphasise the importance of transmission and grid capacity in assessing project feasibility, while also offering improved regulatory certainty for offshore wind development. Moving forward, it will be important to closely monitor how these frameworks are further operationalised and translated into practice through detailed implementation measures, including subordinate enforcement decrees.

D&A
14F, Donghoon Tower, 317 Teheran-ro, Gangnam-gu
Seoul, 06151, Republic of Korea
Tel: +82 2 563 2900
Email: draju@draju.com

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Unlocking the Philippine power market

The Philippines stands at a pivotal moment in its energy transition. Once heavily reliant on imported fossil fuels, the country is now accelerating its shift towards renewable energy (RE), driven by the dual imperatives of energy security and climate resilience. In the past five years, the Philippines’ legal and regulatory framework has undergone substantive reforms, including the liberalisation of foreign ownership for key RE technologies, the streamlining of permitting processes, and the launch of new market mechanisms to scale up the energy transition. The reforms mark the most transformative period for the Philippine energy sector since the passage of Republic Act No.9136 or the Electric Power Industry Reform Act (EPIRA), 2001. As the government pursues RE targets of 35% of the generation mix by 2030, and 50% by 2040, developers are presented with a more open and competitive investment environment.

Legal framework

The country’s RE legal framework is anchored on two statutes. First, the EPIRA restructured and liberalised the electric power industry by opening the generation sector, including RE, to full private sector participation. Prior to the EPIRA, the state operated as a vertically integrated monopoly for generation and transmission, a model that resulted in brownouts and high electricity costs. The EPIRA overhauled this structure by unbundling the industry into generation, transmission, distribution and supply.

The EPIRA further enabled the development of competitive market mechanisms, including the Wholesale Electricity Spot Market and Retail Competition and Open Access (RCOA), which allows qualified consumers to choose their electricity suppliers. These reforms reduced state dominance, enhanced market efficiency and created the institutional foundation for large-scale RE development.

Second, RA No.9513, or the RE Act of 2008, established the targeted policy and incentive framework needed to accelerate RE development, introducing fiscal incentives such as income tax holidays, duty-free importation and value-added tax (VAT) zero rating, significantly improving the bankability of RE projects.

The RE Act also established mechanisms such as: the Renewable Energy Market (REM), which enables the trading of RE certificates; the Renewable Portfolio Standards (RPS), which mandates increasing procurement of RE; and the Green Energy Option Programme, which allows qualified consumers to source their electricity entirely from renewable generators. Collectively, these mechanisms transformed the RE sector from a nascent industry into a central pillar of national energy policy.

These statutes operate alongside the Philippine Energy Plan 2023 to 2050, which charts the government’s long-term vision for a secure and sustainable energy system.

Regulatory bodies

The country’s RE sector is governed by several government agencies with distinct but complementary mandates. The Department of Energy (DOE) is the lead agency responsible for sectoral planning, energy policy formulation, and the award and administration of RE service contracts. It issues circulars governing competitive auctions, market mechanisms and emerging technologies such as offshore wind and hydrogen.

The Energy Regulatory Commission (ERC) serves as the independent regulator tasked with rate-setting and the oversight of the retail and wholesale electricity markets. For RE developers, ERC approvals are critical to achieving commercial operations and securing bankable off-take arrangements.

Environmental oversight falls under the Department of Environment and Natural Resources, which administers the environmental impact assessment system and issues environmental compliance certificates, a prerequisite for project construction.

The National Commission on Indigenous Peoples (NCIP) oversees the free, prior and informed consent process for projects affecting ancestral domains. For RE projects intersecting indigenous lands, NCIP co-ordination is essential to responsible project development.

Foreign ownership

One of the most important recent developments in the RE regulatory landscape is the removal of foreign ownership restrictions. Historically, the 1987 constitution limited foreign participation to 40% in activities involving the exploration, development and utilisation of natural resources, creating uncertainty for RE technologies that rely on natural forces.

This ambiguity was resolved in 2022, when the Department of Justice (DOJ) issued Opinion No. 21 (2022), clarifying that solar, wind, hydro (surface water) and ocean or tidal energy are not natural resources contemplated by the constitution. According to the DOJ, these resources rely on kinetic, not potential, energy and are inherently inexhaustible, distinguishing them from depletable resources such as minerals or fossil fuels. The DOE subsequently adopted this interpretation, formally allowing up to 100% foreign ownership in these RE technologies.

This policy shift is transformative, as it removes a major structural barrier to foreign capital and technology transfer, aligns domestic law with national energy targets, and positions the Philippines to attract large-scale international investment that is expected to accelerate capacity growth in the coming decade.

Investment and development

The investment and development landscape for RE in the Philippines has expanded in recent years, shaped by liberalised ownership rules and rising clean energy demand. With the lifting of the 40% foreign equity cap, the Philippines now offers a more open RE market. As of February 2025, the DOE has awarded more than 1,400 service contracts with a combined potential capacity of about 154GW, including those granted to wholly foreign owned companies for the first time.

Policy-driven demand also reinforces this investment momentum. Under the RPS, electricity suppliers must annually increase their procurement of RE, creating predictable demand for new capacity. The Green Energy Auction Programme complements this by competitively procuring RE at scale, while the RCOA enables corporate renewable procurement by large customers seeking long-term price stability and sustainability compliance.

Despite these gains, developers continue to face structural challenges, including multi-agency permitting despite the Energy Virtual One-Stop Shop, transmission constraints in resource-rich but remote areas, and complex land acquisition and conversion requirements. Certain technologies remain subject to nationality limitations: hydropower projects require water rights available only to Filipino or majority Filipino-owned entities, geothermal resources remain classified as natural resources, and foreign developers generally rely on long-term land leases due to constitutional restrictions on land ownership.

Incentives and trends

The RE Act provides a robust package of fiscal and non-fiscal incentives that underpin the financial viability of RE development in the Philippines. Fiscal incentives include a seven-year income tax holiday, reduced corporate income tax thereafter, duty-free importation of equipment, VAT zero-rating, net operating loss carry-over and accelerated depreciation. These benefits are particularly important for capital-intensive technologies. Non-fiscal incentives include priority dispatch, open access to transmission and distribution systems, and participation in the REM for RE certificate trading under the RPS.

At the same time, emerging technologies are reshaping the country’s clean energy trajectory. The Philippines has become a leading destination for offshore wind, with more than 80 service contracts awarded and extensive pre-development activities underway. Battery energy storage systems are gaining prominence following DOE issuances that recognise storage as integral to managing intermittency and improving reserve margins. Hydrogen development is likewise accelerating, guided by the DOE’s 2024 hydrogen roadmap. Complementary initiatives, including waste-to-energy rules and the recently released carbon credit framework for the energy sector, signal a broader shift towards climate-aligned investment mechanisms capable of unlocking new financing streams and supporting long-term emissions reduction.

The Philippines’ RE sector is entering a defining decade. With a more open investment landscape, strengthened regulatory framework and the integration of new technologies, the country is laying the groundwork for a modern, secure and competitive energy system. While challenges persist, the direction of policy and market reform is clear: RE will form the backbone of the nation’s future power mix.

As global developers bring in capital and expertise, and as the government continues to refine market mechanisms and infrastructure, the Philippines is well positioned to emerge as one of the region’s most dynamic RE markets, capable of meeting ambitious clean energy targets while enhancing energy security and climate resilience.

Cruz Marcelo & Tenefrancia
9th, 10th, 11th and 12th Floors, One Orion
11th Avenue Corner University Parkway
Bonifacio Global City Taguig 1634
Metro Manila Philippines
Tel: +632 88 105 858
Email: energy@cruzmarcelo.com

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Taiwan’s transition to renewable energy

To mitigate carbon emissions, Taiwan targets “net-zero emissions by 2050” by decarbonising its electricity supply. Specifically, the government aims to source 60% to 70% of total electricity generation from renewable energy, with 20% to 27% from thermal power generation utilising carbon capture technology.

Focusing on offshore wind and solar power, the policy framework stipulates an installed capacity of 29GW of renewable energy by 2025, rising to 40-55GW by 2050. Concurrently, the government is actively promoting alternative energy sources including geothermal, biomass, ocean energy and hydrogen energy.

To strengthen the legal framework and ensure power stability while reducing emissions, the Renewable Energy Development Act (REDA) has been continually amended in 2019, 2023 and 2025.

To meet environmental, social and governance (ESG) standards and corporate demand for electricity purchase, the government is also proactively advancing green electricity development through establishing a green electricity trading mechanism, which encompasses amendments to the Electricity Business Act and the REDA. These amendments will facilitate the provision of electricity to end users by renewable energy generators or retailers.

Offshore wind power

The government has delineated offshore wind power development into three distinct phases: the Demonstration Phase (phase I), Potential Sites Phase (phase II) and Zonal Development Phase (phase III).

During phase I, two demonstration projects were successfully developed, between 2013 and 2021, resulting in an installed capacity of about 237MW. In phase II, the Ministry of Economic Affairs (MOEA) allocated grid capacity to a total of 16 projects, including those developed in two stages, culminating in a total installed capacity of about 5.5GW. Notably, 10 of the 16 projects achieved commercial operation between late 2023 and the end of 2025.

Regarding phase III, the government has promulgated a set of regulations governing the allocation of an additional 15GW of offshore wind energy capacity, scheduled for commissioning between 2026 and 2035. Under these regulations, 9GW will be allocated across three phases (designated as R3.1, R3.2 and R3.3) to meet grid connection targets between 2026 and 2031, while the remaining 6GW is slated for commissioning between 2032 and 2035.

Through auction processes, about 3GW of grid capacity was awarded to five projects in R3.1, with an additional 2.7GW awarded to five more projects in R3.2. Formal announcement of the R3.3 auction is expected sometime in the first quarter of 2026.

From phase II, the government launched a set of local content programmes requiring offshore wind developers to commit to engaging with and procuring products and services from local suppliers. The local content requirements became more complex and stringent in R3.1 and R3.2, encompassing localised components including wind turbines, cables, electricity facilities, foundations, vessels and a range of local services.

However, following submission of auction proposals by R3.2 developers in April 2024, the EU requested dispute settlement consultations at the World Trade Organisation (WTO) regarding Taiwan’s local content criteria for offshore wind projects. Subsequently, the EU and Taiwan government reached an understanding concerning the WTO dispute – with the government confirming that no local content requirements will apply to R3.3 or any future offshore wind projects.

However, since the administrative contracts have been signed for R3.1 projects, developers remain obliged to comply with their stipulated local content commitments.

Regarding R3.2 developers, the MOEA issued guidelines to ease review standards for relaxing local content commitments. Specifically, developers may apply for exemption from the commitment if the quantity or delivery schedule of locally produced or supplied products cannot meet the grid connection deadline in the agreement, expected to be the end of
2028 or 2029.

In respect of the R3.3 auction, draft auction rules announced in January 2026 contain the following key features:

1. No mandatory local content requirements but ESG commitments should be provided, with their scope and actual coverage yet to be announced by the MOEA in the formal auction rules.
2. Bidders will be evaluated on technical and financial capacity (minimum 70-point threshold). In the event of a tie, priority will be determined by factoring in the developer’s past performance in Taiwan. A positive track record will enhance scores, while past defaults, delays or poor performance in previous local content commitments will serve as negative indicators. This mechanism is intended to drive the timely and efficient performance of R3.1 and R3.2 projects.
3. To incentivise accelerated construction, “early-bird incentives” have been introduced where projects completed ahead of schedule will be granted a corresponding extension of the term for power sales.

Solar power

Land is a critical factor in the development of large-scale solar projects. Most ground-mounted solar project sites are in non-urban areas. Under the Regional Plan Act (RPA), development of solar projects can only occur on land with permissible zoning and categorised with the required Land Usage Permit according to various usage restrictions outlined in the RPA and its ancillary regulations.

If certain conditions are met, developers must apply for a conversion of land categories and/or zoning to proceed with ground-mounted solar projects.

The government initially planned to reorganise land categorisation by implementing a new set of rules to replace the RPA, known as the Spatial Planning Act (SPA), expected to take effect on 1 May 2025. However, to provide local governments and industries with additional time to adapt to the SPA, the Legislative Yuan postponed implementation of the functional zone regime until 30 April 2031. As a result, the original land conversion regime under the RPA continues to be applicable.

To promote solar projects, the MOEA and the Energy Administration (EA) have actively supported aqua-solar and agri-solar initiatives in the past two years, as well as solar projects that incorporate battery energy storage systems (Solar BESS).

For aqua/agri-solar projects, there are two main challenges:

1. 1. due to certain government restrictions, project companies with majority foreign ownership must collaborate with local land management consultants to obtain and maintain the Land Usage Permit; and
   2. the generation project company is required to ensure that fishery or agricultural production continues alongside the operation of the solar projects for a minimum of 20 years.

Regarding Solar BESS projects, the MOEA and the EA will issue annual guidelines for bidding on these projects. The government offers two key incentives to encourage their development.

First, there are differentiated tariff rates for power discharged by the battery energy storage systems (BESS) compared to that generated by the solar project, with more favourable rates applied to the BESS. Second, successful bidders for grid capacity associated with the BESS may opt to develop a new project with priority rights, equivalent to the capacity of the BESS.

Furthermore, the MOEA will continue to secure land through inter-agency collaboration while increasing installation capacity by pursuing a three-pronged approach to promote solar projects, which includes:

1. 1. Government-to-government coordination mechanism. The MOEA will establish communication channels between central and local governments to reduce market entry barriers for developers.
   2. Rooftop projects incentive. A rooftop incentive mechanism will be introduced to reward small-scale projects, encouraging installations. For new construction, expansion or reconstruction of a building with an area of 1,000 square metres or more, installation of a solar photovoltaic system with minimum installed capacity will be required.
   3. Support and communication platform. A platform for application guidance and communication will be established, featuring a single-window advisory service, a management platform for large projects, and local communication platform.

Other renewable energy

Supporting the net-zero carbon emissions target and commitment to phase out nuclear power, Taiwan’s cabinet and the MOEA are focused on maximising other renewable energy sources alongside offshore wind and solar.

Introduction of new technologies is planned from 2025 to 2035, requiring immediate investment in research funding for areas such as hydrogen, geothermal and ocean energy.

For geothermal projects, since most geothermal potential lies at depths exceeding 3,000 metres, the goal post-2026 is to implement critical technologies like enhanced geothermal systems and advanced geothermal systems.

In the realm of ocean energy, a demonstration site utilising medium-sized floats was expected to be established by 2025. In terms of hydrogen energy, the plan included establishing two hydrogen refuelling stations by 2025.

Lee and Li Attorneys-at-Law
8F, No.555, Sec. 4, Zhongxiao E. Rd
Taipei 110055, Taiwan
Tel: +886 2 2763 8000
Email: attorneys@leeandli.com

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