Beyond generation: building the systems for Asia Pacific’s renewable future 2 November 2026

Japan provides a clear example. Renewable curtailment first became visible in areas with high renewable penetration, including Kyushu, but has subsequently spread across the country, with the Tokyo area experiencing curtailment during 2026. Curtailment is no longer an issue for remote renewable-heavy regions; it is becoming a nationwide structural challenge.

Korea faces a related problem. Grid expansion has not kept pace with renewable deployment, particularly in the southwest Jeolla region, and connection queues have developed. Korea’s Special Act on the Expansion of the National Power Grid, enacted in February 2025, seeks to accelerate transmission and substation infrastructure through centralised coordination and streamlined approvals. The government is also considering an ‘energy hub’ approach for offshore wind, under which shared connection infrastructure would reduce congestion and lower overall connection costs.

Vietnam’s challenge is geographical. Much of its solar and wind capacity is concentrated in south-central and southern regions, particularly in provinces such as Ninh Thuan and Binh Thuan, whilst demand is distributed across the whole country. The Revised Power Development Plan VIII envisages substantial expansion of transmission infrastructure alongside renewable generation and storage.

Indonesia presents the same challenge on a different geographical scale. Under the RUPTL 2025–2034 plan, new renewable capacity has generally been allocated by resource potential rather than by transmission adequacy. The Green Enabling Super Grid programme is intended to overcome this mismatch, connecting renewable-rich outer islands with demand concentrated in Java and Bali through HVDC and smart grid technology. Within parts of the Java-Bali network, however, prior overbuilding of coal-fired capacity has in practice delayed connection of new renewable generation, with PLN in some cases needing two to three years for demand to absorb existing excess capacity.

The significance of the Indonesian model is that the grid is being conceived not simply as infrastructure following renewable development but as infrastructure capable of unlocking renewable resources that might otherwise remain commercially stranded. Network planning becomes anticipatory rather than reactive.

For the commercial analysis, the consequence is straightforward. A project may have an excellent resource and still face material constraints if the network cannot accommodate its output. Conversely, a project with a less exceptional resource but stronger access to transmission and demand may offer a more predictable revenue profile. A renewable resource is only as valuable as the electricity system’s ability to use it.

Flexibility: can the system absorb the output?

Transmission investment alone cannot solve the problem. Electricity systems also need to become more flexible.

Singapore offers perhaps the clearest illustration. Its geographical constraints mean that the transition cannot principally rely on domestic renewable generation. Instead, Singapore is developing a system combining domestic solar, energy storage, flexible demand, digital technology and imported low-carbon electricity. As solar deployment and cross-border imports increase, maintaining system stability is becoming increasingly important, particularly given the reduced inertia traditionally provided by gas-fired generation. The Energy Market Authority (“EMA”) Future Grid Capabilities Roadmap focusses on harnessing distributed energy resources and developing capabilities to maintain stability as renewable penetration increases. A Virtual Power Plant (VPP) Regulatory Sandbox is examining how distributed resources can be aggregated to participate in energy and ancillary-service markets. SP Group is developing a distributed energy resource management system and EMA is supporting research on grid digital-twin technology.

Japan is moving in a similar direction. Japan’s policy focus has similarly shifted from enabling renewable connections to creating a system capable of accommodating much larger volumes. The Agency for Natural Resources and Energy has promoted a nationwide Master Plan for Transmission Networks through OCCTO, and as curtailment has spread, the Ministry of Economy Trade and Industry has proposed measures to absorb surplus generation rather than curtail it, including greater use of storage, flexible demand, pumped-storage hydro and other measures capable of absorbing surplus renewable generation.

This changes what is meant by ‘grid infrastructure’. Storage, software, digital monitoring, demand response and flexible loads will increasingly perform functions historically provided by conventional generation or additional physical network capacity. Assets such as batteries do not always fit neatly within traditional distinctions between generation, consumption and network infrastructure. How they are classified, remunerated and permitted to participate in electricity markets will matter to their commercial value. The regulatory framework must become as flexible as the electricity system itself.

Market access: can the electricity reach the consumer?

Physical access to a network is only useful if electricity can also be sold through it. Electricity-market reform is therefore beginning to converge with grid reform.

Thailand’s developing Direct PPA Framework demonstrates the connection. The pilot originally approved by the National Energy Policy Council (“NEPC”) was designed to enable qualifying data centres to procure renewable electricity directly from generators using third-party access to the electricity network. The NEPC has since resolved to expand the framework to cover other industries seeking access to clean electricity, though detailed implementation arrangements for the wider market remain under development.

Hong Kong approaches the challenge differently. Its longer-term decarbonisation strategy combines local renewable energy with increased access to zero-carbon electricity from Mainland China. The 2026 Policy Address confirms a target for zero-carbon energy to increase from approximately 25% to 60–70% of the generation fuel mix by 2035. CLP’s Clean Energy Transmission System enhancement, connecting to the Daya Bay Nuclear Power Station and the China Southern Power Grid, was completed in March 2026 and is expected to lift the zero-carbon share to around 35%. The government continues to work with Mainland counterparts on further imports and regulatory alignment, with land reserved at Tseung Kwan O Area 132 for further cross-boundary infrastructure.

The electricity system is also extending beyond national borders, reflecting the wider desire to achieve ASEAN electricity interconnection. Singapore is targeting imports of around 6 GW of low-carbon electricity by 2035. By August 2026, EMA had granted Conditional Approvals to 13 import projects sourcing electricity from Australia, Cambodia, Indonesia, Malaysia and Vietnam, with six having progressed to Conditional Licences. Singapore’s expansion of cross-border imports is also raising complex multi-jurisdictional licensing and permitting issues concerning interconnector approvals and subsea cables.

Indonesia is particularly important to this regional story. Proposed electricity exports to Singapore show how domestic renewable development, transmission planning and regional energy integration are beginning to converge. An Indonesian renewable project supplying Singapore may involve generation and storage assets, domestic transmission, subsea cables, maritime rights, Indonesian export approvals, Singapore import approvals and participation in Singapore’s electricity market, each component subject to a different regulatory framework, construction timetable and allocation of risk.

The Lao PDR-Thailand-Malaysia-Singapore Power Integration Project has already demonstrated multilateral electricity trading through existing regional networks. Further development of the ASEAN Power Grid could take this considerably further but interconnection also creates a new category of interface risk. The success of a project may depend not on one regulatory regime or network operator but several.

For developers, lenders and investors, market access and route-to-market clarity increasingly affect how revenue risk is assessed and how PPAs are structured. A project’s ability to demonstrate where its electricity goes, and on what terms, is becoming as important as its ability to generate it.

Cost: who pays for the system?

The scale of required investment raises a difficult question: who pays?

Developers are commonly responsible for dedicated connection infrastructure and may also bear some of the cost of reinforcement required to accommodate their projects. The models vary across markets. In Indonesia, the IPP typically bears the full cost of building connection facilities, but ownership transfers to PLN upon commissioning; PLN absorbs the infrastructure into its regulated network and manages its ongoing operation and maintenance. In Hong Kong, reinforcement costs are recovered through the utility’s regulated capital programme under its Scheme of Control Agreement, with each utility’s permitted return capped at a percentage of its average net fixed assets. The generator faces no direct charge but the pace of reinforcement depends on the utility’s assessment of cost-effectiveness and tariff impact. In Thailand, developers are generally responsible for connection-related costs and may also bear network expansion costs. In Japan and Korea, the allocation of wider reinforcement costs can be complex and may materially affect project economics.

Beyond generation

Asia Pacific still needs substantially more renewable generation. Measuring the transition principally by installed capacity now tells only part of the story.

The first phase of Asia Pacific’s renewable transition was about creating the conditions to build renewable generation at scale. The next phase will be about creating the systems capable of connecting, moving, balancing and getting it to the consumers who want it.

This changes the equation for developers, lenders and investors. Understanding the system around a renewable asset will be as important as understanding the asset itself.

Hanoi Trainee Ha Hoang and Intern Ngoc Nguyen also contributed to this article.