The ASEAN Power Grid: Why every year of delay matters

The ASEAN Power Grid (APG) has been discussed for decades yet built only in fragments. Our modelling shows that one year of slippage beyond the commercial operation date of 2035 will add $2.6 billion in economic losses, accumulating to over $14 billion in five years. Delays will also fundamentally alter the region’s energy transition path as countries get locked in imported fossil fuels for capacity that will still be running in the 2050s. Execution, rather than agreement or capital, is now the constraint for the APG.

ASEAN aims to become the world’s fourth-largest economy by 2045, and electricity sits at the centre of that ambition. Demand is climbing with rising cooling needs, industrial growth, data centres and electrification, yet fossil fuels still meet most of it: coal and gas generated over 73% of the region’s electricity demand in 2025, against around 5% from solar and wind combined.

The region is increasingly reliant on fossil fuels it does not produce, and two energy crises since 2020 have shown the risks of such import dependency. The Middle East supplies about a third of ASEAN’s oil and refined products, and renewed conflict there pushed regional gas prices up by as much as 60% against pre-conflict levels, feeding directly into household bills. Subsidies absorb part of the shock but cannot eliminate the underlying vulnerability. For economies that depend on affordable power to support industry and attract investment, this exposure is a major risk to economic competitiveness.

The APG offers a solution by linking national power systems. It harnesses the pooling effect of geographic diversity, balancing the variability of solar and wind generation, enabling the sharing of reserve capacity, optimising renewable resources across the region and enhancing system security, reliability and market efficiency. The Lao PDR–Thailand–Malaysia–Singapore Power Integration Project (LTMS-PIP) already shows that cross-border interconnections work even across very different market designs, connecting a liberalised market to state-owned utilities through sustained coordination rather than structural harmonisation.

Despite decades since the ASEAN Power Grid (APG) was first conceived as an idea, grid-to-grid cross-border interconnection represents only about 0.5% of the regional demand, and the APG mostly operates as isolated generation-to-grid projects. As reliance on imported fossil fuels leaves the region increasingly exposed to geopolitical shocks, the case for the APG to boost resilience through renewable integration has strengthened recently.

1.1 Most of ASEAN’s power comes from fossil fuels, much of it imported and exposed to geopolitical shocks

ASEAN aims to achieve the target of becoming the fourth-largest economy by 2045, and energy is central to that ambition. One of the key strategies identified by the ASEAN Plan of Action for Energy Cooperation (APAEC) is to deepen economic integration, moving towards a single unified ASEAN economy. The APG sits at the heart of this effort by linking member states through cross-border electricity trade, which strengthens regional partnership while helping power the region’s growth with renewable energy.

At the same time, rising living standards and population growth, compounded by rising cooling demand and new energy-intensive sectors such as data centres and electric vehicles, lead to electricity demand across ASEAN continuing to grow along with the region’s economic development.

So far, coal and gas remain the dominant sources supplying this rising demand. Together, they generated over 73% of ASEAN’s electricity in 2025, while solar and wind contributed only around 5%. The resulting high emission intensity hinders green finance in the region, whose growth is strongly correlated with foreign investment. Besides that, land-constrained nations, such as Singapore, currently have a binary choice to either drastically transform to a clean power system via interconnections or lock into decades of volatile imports of fossil fuels.

All ASEAN member states, with the exceptions of the Philippines and Timor-Leste, have announced net-zero emissions or carbon neutrality ambitions, as of 2026. As the world’s fourth-largest energy-consuming region, Southeast Asia faces the dual challenge of supporting rapid economic and population growth while securing a sustainable energy system.

The Gulf conflict in 2026 further complicates the situation with energy security implications, which hinders economic progress and impacts the livelihood of millions across the region. One-third of the region’s oil and refined products supply comes from the Middle East. ASEAN’s heavy reliance on fossil fuel imports makes it vulnerable to the conflicts and global energy markets, as the regional LNG price was still doubled in May 2026 compared with pre-conflict levels. Although impacts have been partially buffered by government subsidies, the cost of living and inflation are driving up since oil and gas are central to transport, cooking and electricity supply.

Nevertheless, this disruption is also an opportunity for ASEAN to forge novel regional partnerships and reduce its exposure to volatile external fossil fuel markets. The APG offers a way to convert this geopolitical risk into regional resilience through sharing power with neighbours.

1.2 A connected region can achieve far more than isolated countries

The APG is a critical infrastructure to empower regional economic integration, strengthening energy security and accelerating the region’s energy transition. By connecting national power systems, it smooths the variability of solar and wind generation, enables the sharing of reserve capacity, optimises renewable resources across the region and enhances system security, reliability, and market efficiency.

Interconnection enables greater renewable energy integration by harnessing the pooling effect of geographic diversity in both renewable generation and demand profile. Connecting dispersed renewable resources allows surplus generation in one area to offset local shortages caused by diurnal cycles or seasonal variations elsewhere, reducing the need for conventional plants or battery storage to balance variability. Modelling suggests that robust cross-border interconnection can reduce storage requirements in ASEAN by up to 50%, avoiding substantial upfront investment in battery capacity.

The APG also leverages diversity in load profile. Peak demand occurs at different times across Southeast Asia due to differences in time zones, weather, economic activity and consumption patterns. For example, in 2024, Malaysia’s daily peak demand coincided with that of neighbouring Thailand or Singapore on only around 30% of days. By pooling these diverse demand profiles, the region no longer needs to maintain enough capacity to meet the sum of every country’s individual peak demand simultaneously. Instead, countries can share generation and reserves, reducing the need for standby peaking capacity, lowering system costs and improving overall asset utilisation. An ASEAN study found that while cross-border transmission accounts for less than 0.5% of total system costs, it reduces cumulative system costs by up to 11.9%.

In addition, the APG enables renewable energy to be developed where resources are most abundant and cost-effective, which reduces land requirements and improves resource utilisation. For instance, land-constrained Singapore could meet part of its growing electricity demand by importing solar power from Cambodia, wind power from Viet Nam and hydropower from Sarawak. At the same time, the APG creates significant economic opportunities for resource-rich countries such as Indonesia and Lao PDR by allowing them to monetise their renewable resources through electricity exports. The ASEAN Centre of Energy estimates that more than 60 GW of solar and wind capacity has been identified along APG corridors, representing a substantial pipeline of projects to support the region’s energy transition.

Beyond enhancing operational flexibility, regional interconnection strengthens energy security by enabling greater renewable energy integration, therefore reducing reliance on gas imports and the associated geopolitical risks such as the ongoing conflicts in the Middle East.

Interconnection also provides critical contingency support, enhancing reliability during emergency events, which is especially valuable for regions prone to extreme weather events such as typhoons and floods, such as ASEAN, where unplanned outages are more frequent. The World Bank estimates the economic costs for power outages during two dry months in Viet Nam in 2023 are about $1.4 billion.

Accelerating the regional grid brings massive structural cost savings. A study shows that a regional interconnected system can reduce about $800 billion from the overall cost of ASEAN decarbonisation by 2050 compared with individual country transitions. This aligns with findings from the ASEAN Interconnection Masterplan Study (AIMS III), as it demonstrates that the benefits from lower generation costs and avoided thermal power investments outweigh the costs of additional transmission and renewable energy infrastructure.

Regional interconnection also improves market efficiency by increasing competition. International experience has shown the great economic value of regional electricity markets. For instance, the Western Energy Imbalance Market in the United States (US) delivered approximately $3.4 billion in benefits between 2014 and 2022 through reduced renewable curtailment and lower reserve requirements. The European power market is estimated to save consumers around €34 billion annually through cross-border electricity trading and more efficient use of generation resources.

1.3 Decades of discussion, little progress on the ground

Even though the concept of the APG was first articulated almost three decades ago in 1997, total cross-border grid-to-grid power exchange represents only about 0.5% of regional electricity demand between 2016 and 2022. Cross-border transmission operates primarily through isolated generation-to-grid projects, mostly from Lao PDR to Thailand, Cambodia and Viet Nam. Grid-to-grid integration remains constrained within sub-regional frameworks like the Lao PDR-Thailand-Malaysia-Singapore Power Integration Project (LTMS-PIP), and the Brunei-Indonesia-Malaysia-Philippines framework (BIMP-PIP), which still remains in the feasibility stage now. Currently, subsea interconnection across ASEAN is essentially limited to a single project, which is the Plentong–Woodlands link built in 1985 between Malaysia and Singapore.

Continuing to postpone the execution of the APG will affect the region significantly. Chapter 2 models different scenarios to highlight the costs of delaying the implementation of the regional power grid, while Chapter 3 delves deeper into the bottlenecks and offers possible solutions.

Delaying the implementation of the ASEAN Power Grid (APG) risks costing ASEAN an economic loss of up to $2.6 billion for each year of slippage from the target 2035 commercial operation date. The cost of a five-year delay rises to almost $14 billion. In addition, fossil fuel lock-ins and emissions implications are other painful costs of a delay.

This chapter quantifies the opportunity cost of delaying the implementation of the APG, which delivers value through lower system cost, improved energy security, system reliability and reduced emissions.

To evaluate how regional grid integration shapes ASEAN’s energy transition, the study models the expansion of generation, storage and cross-border transmission during 2025-2040 under two main scenarios: a base case scenario and a delay scenario with a one-year delay; along with a sensitivity case with a two- and five-year delay. Modelling scope, assumptions and framework are detailed in the Methodology section.

This modelling does not aim to provide definitive COD forecasts for individual projects. Instead, it evaluates the potential system impacts of delays in APG implementation and highlights the importance of timely investment and coordinated action among stakeholders to accelerate regional grid integration.

2.1 Base case: the APG will enable rapid renewable build-out and cross-border electricity trade

While the ASEAN Ministers on Energy Meeting (AMEM) targets the full realisation of the APG by 2045, this analysis assumes that all transmission projects associated with Singapore and other priority projects will achieve commercial operation dates (CODs) by 2035, aligned with Singapore’s target to import 6 GW of low-carbon electricity by 2035. The only exceptions are the interconnection projects linking Lao PDR with Cambodia and Myanmar, which are assumed to be commissioned by 2030 based on projections from the ASEAN Centre for Energy.

While some projects, such as the Peninsular Malaysia–Singapore Interconnection, have announced target CODs as early as 2030, a 2035 timeline is considered more realistic given the long development lead times associated with subsea cable projects and cross-border transmission infrastructure in general.

Clean power dominates the regional mix under least-cost optimisation

In the base case, meeting the projected electricity demand across the region requires approximately 400 GW of additional generation and storage capacity by 2040. Clean energy emerges as the optimal expansion pathway, accounting for more than 90% of total capacity additions over the planning horizon.

Benefiting from the location within the sunbelt region, with abundant year-round solar resources and rapidly declining capital costs, solar PV represents the largest share of new capacity, contributing over 250 GW by 2040 in ASEAN. Additionally, the modelling projects ASEAN to develop more than 26 GW of wind capacity, 34 GW of hydropower and up to 46 GW of battery storage over the next 15 years to support system flexibility and renewable integration.

In the cost-optimal pathway, a reduction of over 3 GW of coal is also projected by 2040, primarily due to plant retirement without any new-built replacement. In many countries in ASEAN such as Malaysia and Thailand, there have been announcements that coal will not be considered for expansion, whereas countries like Viet Nam plan to peak coal capacity in 2030 and phase out thereafter.

Solar capacity increases across the region in the cost-optimal pathway

As mentioned, solar dominates the regional capacity mix in the base case, accounting for over 60% of new capacity added across the modelled region by 2040. Lao PDR is the only exception, as existing and planned hydropower is sufficient to meet projected domestic demand, so solar capacity grows only marginally from 40 MW in 2025 to around 70 MW by 2040.

In the cost-optimal pathway, Viet Nam is the region’s leading country in solar capacity additions, installing around 100 GW of additional solar to reach over 120 GW by 2040. The modelling result is consistent with Viet Nam’s national target of up to 295 GW by 2050. Subsequently, tapping into its 300 GW solar potential, Thailand follows as the second-largest solar market in the region, developing an additional 70 GW by 2040. Meanwhile, solar capacity in Peninsular Malaysia and Indonesia’s Sumatra will each pass 30 GW, while land-constrained Singapore maximises its potential to reach over 6 GW by 2040.

Part of the solar growth in the base case can be attributed to the commissioning of the APG by 2035, especially for solar-rich regions such as Cambodia, Indonesia’s Sumatra and Myanmar, where the interconnectors enable a good business case to export renewable electricity to high electricity-demand neighbours such as Singapore and Thailand.

Electricity flows across ASEAN could far exceed Singapore’s entire electricity demand by 2035

If all the planned priority interconnectors are built by 2035, total cross-border flows of the modelled region will amount to around 120 TWh. This well exceeds Singapore’s projected electricity demand of the same year at about 97 TWh, which is the upper-bound forecast of the Singapore market authority.

Lao PDR is now the fifth-largest electricity exporter in the world and will continue to be one of the biggest exporters in the region by 2035. The nation has generated $2.35 billion in 2024 by exporting electricity to all its neighbours, mostly to Thailand. The country aims to double its hydro capacity to 20 GW by 2030 to increase electricity export revenue. The model estimates that Lao PDR can export around 24 TWh of electricity by 2035, including over 8 TWh to Thailand and around 5 TWh to Viet Nam.

The northern part of the region is expected to see a significant increase in electricity trade if the planned interconnectivity is materialised. Myanmar has exported over $1.7 billion worth of petroleum gas to Thailand in 2024. Despite having no national grid integration as of now, up to 9 TWh of electricity could be transferred from Myanmar to Thailand in 2035 through interconnectors. This enables the country to switch to renewable energy export, and to make use of its large solar and hydro potential while making revenues essential for social development.

Singapore’s clean energy goals will be a key beneficiary of the APG in the base case. The Sumatra–Singapore interconnection emerges as the largest electricity trading corridor, with both the highest transfer volume and the largest installed capacity at 3,400 MW. The subsea cable projects seem on track to reach commercial operation by 2035, as both countries are actively working to resolve the obstacle to electricity pricing. The model projects that the interconnectors can deliver more than 26 TWh from Sumatra to Singapore in 2035, operating at approximately 87% utilisation, highlighting their critical role in supporting Singapore’s energy transition target. Other interconnections supplying Singapore, including links from Cambodia and Viet Nam, also operate at high utilisation levels, on average at over 75% and 90%, respectively. Currently, Viet Nam plans to build a subsea cable to export offshore wind to Singapore, while Cambodia also plans to export 1 GW of renewable energy to Singapore.

These high-utilisation corridors demonstrate the potential high value of investment return, as heavily utilised interconnectors can generate high economic incomes. For example, the Nemo Link interconnector between the UK and Belgium generated revenues of £116.9 million above its regulatory cap in 2022 at around 65% utilisation.

2.2 Delay scenario and sensitivity case: the cost of delaying the APG

An interconnected ASEAN by 2035 will unlock a highly efficient renewable energy system, with cross-border trade exceeding 120 TWh annually. Our modelling shows that the delay of construction will leave ASEAN behind not only with fossil lock-in but also with a huge amount of costs.

This section evaluates the effects of project delays by comparing the delay scenario with the base case, which assumes most of APG will be commissioned by 2035. In the delay scenario, all interconnection projects scheduled for commissioning in the base case are assumed to be deferred by one year.

Although the postponement is relatively short with only one year, the results reveal substantial regional consequences by 2040, including economic losses of $2.6 billion, increased gas consumption by over 12 billion cubic metres, and 42 million tonnes of higher CO2 emissions. These findings underscore the importance of delivering transmission infrastructure on schedule to fully realise the benefits of regional power integration.

Cost of delay accumulates: One year $2.6 billion accumulates to $14 billion over five years

Since delaying the interconnections alters the model’s objective function over the entire planning horizon to 2040, the optimisation problem of the delay scenario differs from that of the base case. Consequently, the impacts are assessed using cumulative outcomes through 2040 rather than considering 2035 alone.

Across the region, the delay scenario incurs substantially higher fuel costs due to reduced renewable capacity additions resulting from the absence of the APG by 2035. Cumulative fuel expenditures of the delay scenario by 2040 are about $5.6 billion greater than in the base case.

In contrast, the interconnections enable greater deployment of capital-intensive renewable generation by 2035 in the base case compared to the delay scenario. As a result, cumulative capital expenditures by 2040 in the base case (about $424 billion) exceed those in the delay scenario (about $421 billion) by more than $3 billion. Nevertheless, the savings in fuel costs outweigh these additional investments. Overall, commissioning the APG in 2035 rather than 2036 yields a net regional benefit of approximately $2.6 billion.

A one-year delay in the APG also increases cumulative gas consumption by about 12 bcm, which is higher than Singapore’s gas consumption in 2024 at 11 bcm. If this gas volume was sourced from imports, the amount is equivalent to the cargo capacity of roughly 78 Q-Max LNG carriers. The Q-Max vessel is currently the largest LNG carrier in the world, each capable of transporting around 260,000 m³ of LNG, assuming that the volume reduction ratio from gas to LNG is 600 times.

Environmentally, the delay scenario results in an addition of more than 42 mtCO2 emissions. Offsetting this amount would require approximately 46 million trees growing for 50 years, assuming an average sequestration rate of 18.3 kg CO2 per tree per year.

A longer delay of the APG by five years could impose an additional cost of approximately $14 billion on ASEAN by 2040. These higher costs would ultimately be borne by consumers, either directly through higher electricity prices or indirectly through government subsidies.

Additionally, the five-year delay increases cumulative gas consumption by more than 55 bcm by 2040, a volume which exceeds 2024 gas consumption of Thailand at 42 bcm and Singapore at 11 bcm combined, and raises CO2 emissions by over 71 million tonnes – an amount almost equivalent to the Philippines’ power sector emissions in 2025.

Over 7 GW of solar capacity will be put on hold while an additional 3.5 GW of battery is required and 0.3 GW of gas is locked into Singapore

Interconnections can raise the ceiling of how much renewables a country can build in the least-cost pathway. They can help optimise the best renewable resources in the region such as solar in Cambodia, offshore wind in Viet Nam and hydro in Lao PDR and Myanmar to supply demand in countries that have scarce resources such as Singapore. In doing so, they not only reduce total system costs but also create export revenues for resource-rich countries.

Without the full commissioning of the APG, 7.2 GW of solar and 2.2 GW of hydropower capacity would not be developed on a least-cost basis in ASEAN in 2035. Most of the forgone solar capacity is in Indonesia’s Sumatra (4.9 GW) and Cambodia (1.4 GW), directly cutting planned renewable power exports to Singapore. Similarly, around 1.9 GW of solar and 1.1 GW of hydro capacity in Myanmar become economically unjustified to build without access to northern APG corridors.

By contrast, in the delay scenario regional battery storage capacity increases by about 3.5 GW in 2035 relative to the base case. In the absence of interconnectors capable of evacuating surplus daytime solar generation, additional storage is required to arbitrage energy to evening hours, highlighting the complementary and substitution roles of transmission infrastructure and battery storage. In addition, the delay of interconnections eliminates access to shared reserve capacity across borders. As a result, more battery storage must be deployed to meet reserve margin constraints and ensure resource adequacy. Geographic diversity and cross-border balancing help reduce the need for battery storage, so this avoided investment in total system cost should be accounted for in the benefits of interconnectors.

On a national level, without the APG to supply the rising demand, Singapore must install an additional 300 MW of gas-fired capacity to meet demand in 2035. Although renewable imports enabled by the interconnections eliminate the need for this capacity from 2036 onwards, gas plants typically have economic lifetimes of around 25 years and a minimum take-or-pay contract of about 70%, thereby increasing long-term fuel costs due to the lock-in of gas-fired infrastructure.

In the delay scenario, as the APG is completed in 2036, greater renewable energy deployment occurs after that point. However, because additional battery storage and gas capacity had already been built to meet demand in 2035, these long-lived assets remain in the system, limiting further renewable capacity expansion by 2040. As a result, compared with the base case, the delay scenario retains around 200 MW more battery storage and 400 MW more gas capacity, but develops 1.4 GW less hydropower by 2040.

A one-year delay of the regional interconnection will increase gas generation by over 50 TWh

As a consequence of the reduced renewable build-out, to fill in the missing supply of renewables, gas-fired generation increases by more than 50 TWh across the region by 2040, roughly 3.6% of ASEAN electricity demand in 2025. Our modelling reflects that one of the most important roles of the APG is moving cheap renewable energy from where it is to demand centres that are overwhelmingly gas-fired, such as Singapore, Thailand and Malaysia. Without the interconnection, those systems simply serve that demand with their own gas-fired power plants.

Besides that, a one-year delay to the APG would dismiss the supply of more than 36 TWh of renewable electricity, including over 13 TWh of solar. Export-oriented renewable projects in Sumatra, Cambodia, Lao PDR and Myanmar depend on transmission links to secure long-term off-take agreements and financing. Without the interconnectors, these projects are unlikely to proceed. The consequences extend well beyond the one-year delay, as investment decisions deferred during that period are replaced by gas-fired plants, for example the 300 MW in Singapore, which typically remain in operation for 20–30 years. The result is not a temporary supply shortfall, but a long-term fossil fuel lock-in.

This analysis assumes that cross-border trade is driven by least-cost optimisation under the projected price trajectory. In practice, whether interconnection displaces gas or simply enables continued gas trading between systems depends on relative nodal price signals such as locational marginal pricing and on governance mechanisms such as carbon tax and emission accounting framework. These instruments will be discussed further in Section 3.2 and are essential to ensure interconnectors are primarily used to move clean generation rather than fossil-fired power.

Singapore to suffer most with APG delays

About 40% of the APG’s interconnection capacity is directed towards Singapore, making it also the country most affected by project delays. Owing to its limited land availability and constrained renewable resources, with domestic solar potential only around 6.6 GW, Singapore has few viable pathways to decarbonisation other than importing renewable electricity from neighbouring countries.

Depending on whether APG is commissioned by 2035, Singapore now finds itself at a crossroads in its energy policy. Planned interconnections could let renewables satisfy up to 49% of its electricity demand; on the other hand, delaying can drop that number to 2.5% in 2035.

Gas currently provides more than 90% of Singapore’s electricity generation. Without timely completion of the APG, the country would have little choice but to continue relying on gas, which could still account for over 86% of electricity supply in 2035.

Delaying economic leverage: $1.1 billion per year in missed export revenues

Without the interconnectors, resource-rich regions such as Lao PDR, Cambodia, Myanmar and Sumatra lose valuable export opportunities to major electricity markets, including Singapore, Thailand and Viet Nam. Although these regions possess abundant solar and hydropower resources, their relatively modest domestic demand constrains the development of these assets in the absence of cross-border transmission.

With the assumed levelised cost of exporting electricity for solar at $30/MWh and $60/MWh for hydro, the forgone value of electricity exports from these regions could exceed $1.1 billion every year of delaying the APG. Indonesia’s Sumatra is particularly affected, losing nearly $400 million in potential revenue from solar and hydropower exports to Singapore.

Lost export revenue is not delayed but rather missed opportunity income, so it is gone forever if the APG fails to come online as planned. Given that electricity demand cannot wait, countries are forced to lock into long-term fossil fuel infrastructure, exposing them to supply disruption and volatile prices. In other words, delaying the regional transmission grid not only causes economic and reliability loss, but also undermines broader energy security and sustainability goals.

2.3 Key takeaways of the modelling

• Regional optimisation unlocks greater system value. Planning the power system at the ASEAN level, rather than country by country, delivers significantly greater economic and reliability benefits. Cross-border interconnections enable the sharing of reserve capacity, improve resource adequacy during system contingencies and optimise the deployment of renewable energy by accessing the region’s best wind, solar and hydropower resources.
• Delaying the APG creates long-term fossil fuel lock-in. The APG is a critical enabler of large-scale renewable energy integration. Delaying transmission infrastructure postpones renewable investments, encourages additional gas-fired generation and locks fossil power plants into the system for decades, increasing stranded asset risks and making long-term decarbonisation more costly. Accelerating APG development alongside national power planning is essential to avoid this lock-in.
• Transmission and batteries are complementary investments. In an interconnected system, geographic diversity and cross-border balancing displace part of the battery fleet that each isolated system would otherwise need. The avoided storage investment offsets a share of the transmission capital in total system cost and should be counted on the benefit side of the interconnector business case.
• The APG strengthens energy security while creating new export markets. Regional interconnection reduces dependence on imported fossil fuels and improves resilience against global fuel price volatility and geopolitical supply disruptions. At the same time, it enables resource-rich economies to monetise abundant renewable resources through cross-border electricity exports.
• The only viable pathway for land-constrained economies. For countries with limited domestic renewable resources or land availability, such as Singapore, the APG provides access to low-cost renewable electricity that cannot be developed domestically, making it indispensable for achieving deep decarbonisation targets.

The APG’s biggest bottleneck is governance rather than economics. Regional bodies coordinate planning without the authority to enforce it, while national rules on transmission access and export permits make cross-border projects difficult to finance. The way through is a layered, voluntary path from bilateral deals towards multilateral trade, underpinned by harmonised and transparent transmission tariffs that let investors see how costs will be recovered.

With the political will and capital available, the APG remains largely unbuilt because of a lack of institutions, rules and revenue frameworks. While agreement has been reached through high-level communications and master plans, it has not yet translated into the enforceable obligations, harmonised standards and cost-recovery arrangements that infrastructure of this scale requires.

3.1 Challenges

The modelling in Chapter 2 highlighted the significant economic loss of delaying the APG. It is now important to assess the reasons behind the bottleneck of implementation. This subchapter lists the issues that cause the delay of APG projects.

Authority gap, regulatory constraint and implementation challenges

One of the APG’s biggest hurdles is the institutional gap. Fragmented regulatory frameworks with the absence of harmonised technical and market rules continue to slow down progress. Multiple ASEAN bodies coordinate planning, yet none possess the authority to enforce decisions, drive project implementation or mandate the real-time cross-border data sharing needed for efficient power trading.

However, global experience demonstrates that cross-border market integration does not need to wait for fully developed institutions. For example, the European Network of Transmission System Operators for Electricity (ENTSO-E), which holds regional institutions to issue legally binding obligations to national system operators, was established in 2008, two years after the first multilateral market coupling in Europe in 2006. Given ASEAN’s decentralised governance model, ASEAN members will need innovative institutional arrangements that strengthen regional coordination while respecting national sovereignty.

National regulations also create barriers to investment and cross-border electricity trade. In Indonesia, for example, third-party access to electricity transmission infrastructure is not permitted, limiting opportunities for private sector participation in regional interconnection projects. Indonesia also requires renewable electricity export permits to be renewed every five years, whereas investors typically require 20–25 years of regulatory certainty to finance capital-intensive infrastructure such as renewable power plants or subsea interconnectors. This mismatch between regulatory timeframes and investment horizons substantially increases project risk and financing costs.

Beyond governance and regulation, cross-border transmission projects face complex permitting and implementation challenges. Transmission corridors frequently traverse environmentally sensitive or protected areas, requiring extensive environmental assessments and stakeholder consultation. Land acquisition, social opposition and the technical complexity of constructing long-distance transmission infrastructure can further delay project development and increase costs.

Financial, market and technical hurdles

Bankability is another major block for progress with the APG. The International Energy Agency estimates that APG interconnections require around $27 billion by 2040. This can rise to $100 billion by 2045 if domestic grid upgrades are included, according to the Asian Development Bank. Even though quite substantial, the required investments are likely to be manageable if capital from multilateral banks and private investors is effectively mobilised. Yet clean power capital continues to be underestimated. ASEAN invests only $0.80 in clean energy for every $1 spent in fossil fuels, which is far behind the global average of $2 to $1. To shift capital allocation, the region urgently needs investment-ready interconnection projects.

The main barriers to bankability are back to regulatory and market constraints such as lengthy permitting processes, regulatory uncertainty and inconsistent market frameworks across ASEAN.

Transmission projects often require approvals from multiple agencies and jurisdictions, extending development timelines and increasing financing costs. Investors also face uncertainty over licensing arrangements, wheeling charges, transmission tariffs and cost recovery mechanisms. Such prolonged regulatory processes weaken project economics by delaying revenues and increasing development risk, making it more difficult to secure long-term financing.

Cross-border subsea transmission projects face additional technical and commercial challenges. High-voltage direct current (HVDC) submarine cables require significant upfront capital investment and typically have development timelines of 10–12 years. Routing must avoid submarine volcanoes, seismic zones, deep ocean trenches and busy shipping and fishing corridors, while projects might face environmental side effects, social protest and difficulty of construction. Global supply chain constraints can further complicate deployment. Prices for power transformers and submarine cables have nearly doubled since 2018, manufacturing capacity remains constrained and specialised cable-laying vessels are operating close to full utilisation worldwide, with only a handful capable of installing the HVDC subsea cables.

Financing conditions in ASEAN also remain less favourable than in advanced economies. Higher financing costs, exchange rate risks and the limited borrowing capacity of many state-owned utilities reduce the attractiveness of large transmission investments. Uncertainty over who should finance, own and recover the costs of cross-border transmission assets further complicates investment decisions.

Differences in electricity market structures also present a major obstacle to regional integration. ASEAN comprises a mix of vertically integrated state-owned electricity systems and liberalised wholesale markets, such as those in Singapore and the Philippines. These incompatible market architectures create challenges for dispatch, settlement, pricing and congestion management in cross-border electricity trading. Developing mechanisms that allow these different market models to operate together will require close government cooperation and harmonised regional market rules.

Finally, investment risks extend beyond construction and financing. Developers face uncertainty over the allocation of commercial risks between governments, utilities and private investors. Reliance on retail off-take models can expose projects to counterparty risk, as demonstrated during Singapore’s 2022 energy crisis when several electricity retailers exited the market. Establishing robust long-term contractual frameworks and clear risk-sharing arrangements will therefore be essential to attract private investment into regional transmission infrastructure.

3.2 Recommendations

The challenges are solvable, but overcoming them requires a shift in political focus, from setting ambitions to sustained implementation. This means continuing to strengthen long-term political commitment, improve regional collaboration to make projects bankable and standardise bilateral arrangements while building the foundations for more sophisticated multilateral trading. This subsection lists the ways to make those changes and help address the barriers delaying the APG.

Political discourse needs to shift from keen discussion to sustained commitment and active coordination

Despite the strong technical and economic case for regional electricity trade, integration ultimately depends on political trust, sustained leadership and effective cooperation. Although cross-border interconnections can reduce system costs and improve energy security, they also require significant upfront investment and create deeper regional interdependence, raising concerns around sovereignty, reliability and equitable benefit sharing. Since transmission infrastructure requires decade-long development timelines, sustained political commitment that spans beyond political cycles is essential to translate regional ambitions into lasting, long-term cooperation.

The Lao PDR–Thailand–Malaysia–Singapore Power Integration Project (LTMS-PIP) proves it is doable. This case demonstrates that connecting different market designs, such as Singapore’s liberalised system and neighbouring state-owned utilities, does not require total structural harmonisation. Instead, it requires active coordination. The LTMS-PIP took more than one hundred working groups, alongside a shared digital coordination platform, to facilitate system balancing and operational alignment. Effective information sharing and institutionalised cooperation mechanisms are therefore key to scaling regional electricity trade in ASEAN.

Address financial risks and uncertainty to unlock investments

The bankability of cross-border transmission infrastructure in ASEAN is shaped by revenue frameworks, financing conditions and the broader policy environment. Unlike domestic generation assets, regional transmission projects depend on complex arrangements for cost recovery across multiple jurisdictions, making revenue certainty and tariff design central to investment viability.

A key gap is the absence of harmonised and transparent transmission tariff frameworks. Tariff structures directly affect project economics and the final electricity price for end-users, yet current arrangements are largely negotiated on a case-by-case basis with no standardised approach to allocating costs, risks and benefits across countries. As a result, transaction structures are complex, slow to negotiate and difficult to scale. Regionally coordinated wheeling charges and transmission tariffs that ensure cost recovery, economic efficiency, fairness, transparency and predictability would improve price visibility, reduce transaction costs and strengthen investor confidence.

Commercial arrangements should also progressively shift from bespoke contracts toward more regulation-based frameworks. Regional models such as the West African Power Pool, which introduced coordinated approaches to transmission charging, demonstrate how greater standardisation can improve investment visibility and reduce transaction costs. Ideally, cost sharing should be done according to a beneficiary pays principle, where the costs are shared in proportion to each party’s received benefits.

In addition, international experience has highlighted the value of leveraging dedicated regional financing mechanisms. For example, the Connecting Europe Facility for Energy provides public funding for energy projects that benefit multiple countries, which recognises that cross-border projects can deliver benefits beyond the country where the infrastructure is built. In ASEAN, initiatives such as the ASEAN Power Grid Financing Initiative (APGFI) can play an important role in mobilising capital by using support from multilateral development banks and private investors to de-risk early-stage APG projects, funding feasibility studies, standardising financing approaches and further crowding in private capital.

Additional revenue stabilisation mechanisms could also enhance bankability. Availability-based payment structures, as used in Brazil, provide predictable long-term income streams that reduce revenue volatility and improve financing conditions for capital-intensive grid infrastructure.

Another way to unlock green finance in cross-border interconnection investment is to build a regional framework for carbon accounting. Harmonised methodologies such as Energy Attribute Certificates (EACs) for measuring the carbon intensity of imported electricity can allow end-users to substantiate and report progress on emissions avoided through grid connections. Additionally, to provide stronger and more consistent price signals for low-carbon electricity, it is important to continue strengthening the scale-up of market-based carbon instruments, such as carbon tax or emission trading schemes. This is particularly relevant for markets such as Singapore, where carbon pricing plays an important role in shaping electricity import economics.

Finally, emerging corporate demand for clean electricity presents a significant opportunity to strengthen project bankability. Global technology companies like Microsoft, Google and Amazon increasingly sign long-term renewable energy procurement agreements due to corporate commitment to renewable energy. Initiating and streamlining supportive policies such as Cross-border Power Purchase Agreement and 24/7 Carbon-Free Energy framework can attract corporate capital, which provides stable, long-term revenue streams that help anchor financing for large-scale cross-border renewable energy and transmission infrastructure in ASEAN.

Start with bilateral projects but switch to multilateral power trade in the long run

Although LTMS-PIP is often described as ASEAN’s first multilateral power trade initiative, in practice it remains a series of coordinated bilateral contracts rather than a fully integrated regional electricity market. While this structure has been effective for initial cross-border projects, it does not yet fully unlock the benefits of multilateral power trade (MPT), particularly in terms of optimising interconnector utilisation and enabling broader system-wide efficiency. MPT arrangements can enhance bankability by increasing utilisation of cross-border interconnectors from around 60% under bilateral trading arrangements to as high as 90%. While bilateral arrangements remain more pragmatic in the near term due to lower requirements for institutional harmonisation and faster implementation timelines, the governance and institutional frameworks for the APG should be built for easy expansion to MPT in the future.

A mature MPT framework would allow interconnectors to be used more efficiently by enabling power flows based on system-wide optimisation rather than bilateral arrangements alone. By expanding the geographic and technological diversity of supply, MPT would improve system flexibility, reduce costs and enhance renewable energy utilisation.

A key principle guiding ASEAN discussions is that MPT development should proceed on a layered market approach and voluntary and stepwise basis. This allows the coexistence of multiple trading mechanisms without a central authority imposing a unified market design. Such an authority, however, will be required for the future fully integrated regional market. Multilateral cross-border markets are expected to evolve gradually through coordination supported by regional institutions and development partners, broadly similar to approaches observed in other federated electricity markets, such as those in Africa and Central America.

In this context, a subregional-led pathway is suitable to advance MPT by building on existing bilateral initiatives such as LTMS and the BIMP interconnections, alongside the introduction of secondary short-term energy trading mechanisms among already interconnected countries. These would allow generation surpluses and deficits to be traded on a voluntary basis, with the system gradually expanding in geographic scope and market sophistication over time towards a fully integrated regional platform.

Ongoing initiatives such as the ASEAN Interconnection Masterplan Study III (AIMS III) Phase 3, including guidelines on regional planning, minimum technical standards harmonisation and implementation strategy, represent important steps toward progressively enabling a more integrated multilateral power trade framework in ASEAN.

Supporting materials

Methodology

Cross-border interconnection and identified renewable energy resources along the corridors

The ASEAN Power Grid (APG) shown in the infographic in Section 1.2 covers the entire region, while the modelling in Chapter 2 covers only part of the network, as described in the “Scope and modelling framework” section below. The infographic includes only existing grid-to-grid interconnections. Existing and planned interconnector capacities were taken from the ASEAN Centre for Energy (ACE) ASEAN Power Grid Interconnection Profiles. For planned projects, the higher capacity from the updates provided by HAPUA Working Group 2 and the AIMS III Phase 1 and Phase 2 ASEAN Renewable Energy Target Scenario was used. The Singapore–Sarawak interconnector was additionally included based on the Energy Market Authority (EMA)’s 2025 announcement.

Solar and wind energy resources along the interconnector corridors were identified primarily using the ACE report above. Cambodia’s renewable resources were based on EMA’s announcement on electricity imports from Cambodia, while hydropower resources in Sarawak were based on EMA’s announcement on electricity imports from Sarawak. Lao PDR’s onshore wind and hydropower resources were based on announcements from the Lao government and project developers. Myanmar’s hydropower resources were based on the country’s Energy Master Plan. Finally, Viet Nam’s offshore wind resources were based on EMA’s announcement on electricity imports from Viet Nam.

Scope and modelling framework

The study examines the potential impacts of delaying ASEAN cross-border electricity interconnectors during the planning horizon from 2025 to 2040. The geographical scope includes Viet Nam, Lao PDR, Cambodia, Thailand, Myanmar, Singapore, Peninsular Malaysia and Indonesia’s Sumatra, as these areas exhibit the highest demand for cross-border electricity trading and have the most active interconnection initiatives based on recent government announcements. Other APG projects are excluded from this study and will be considered in future work.

As a result, the modelling outputs presented in Chapter 2 are limited to this geographical scope. For brevity, however, the general terms ASEAN, regional interconnections and APG are used throughout the chapter but only refer to this particular scope of the region.

A quantitative modelling approach was employed using TransitionZero’s Scenario Builder platform to model long-term capacity expansion. The model framework is based on TZ-OSeMOSYS that minimises the total discounted cost of the regional power system over the planning horizon. The model optimises the location, technology and capacity of electricity generation while simultaneously determining electricity flows across the transmission network, considering localised generation costs, resource availability and transmission capacities.

Data and assumptions

Electricity demand projections were compiled from the latest national planning documents where available. Demand for Myanmar and Lao PDR is based on the WWF report Towards a Green and Inclusive Power Sector in the Greater Mekong Subregion. Thailand’s demand follows the Draft Power Development Plan (PDP) 2024, with demand from 2038 to 2040 projected using the compound annual growth rate (CAGR) over 2025-2037. Viet Nam follows the Revised Power Development Plan VIII (RPDP 8, 2025). Cambodia adopts Scenario 2 from the Draft PDP 2024. Demand for Peninsular Malaysia is derived from the Report on Peninsular Malaysia Generation Development Plan 2020 (2021–2039), with annual electricity demand extrapolated from projected peak demand. Singapore uses the upper-bound electricity demand forecast published by the Energy Market Authority (EMA), accounting for the projected growth of data centres’ demand with the assumption that the annual growth rate during 2035–2040 remains equal to that observed between 2033 and 2034. Electricity demand for Indonesia’s Sumatra is based on Indonesia’s RUPTL 2025, with demand beyond 2035 projected using the CAGR over the period 2025–2034.

Only existing grid-to-grid transmission projects are considered in this study. All planned interconnectors are assumed bidirectional to evaluate the potential of multilateral power trading, except for the two lines from Indonesia’s Sumatra and Peninsular Malaysia to Singapore being unidirectional due to the vast imbalance of import needs between the regions.

Generation capital costs (CAPEX) are sourced from multiple references. Viet Nam adopts technology cost assumptions from the Danish Energy Agency’s (DEA) Viet Nam Technology Catalogue. Indonesia’s Sumatra uses the DEA Indonesia Technology Catalogue. Coal, gas, solar and wind technologies for Thailand and Malaysia are based on BloombergNEF reports specific to each country. Cambodia, Lao PDR and Myanmar are assumed to have CAPEX values equal to the average of Viet Nam and Thailand, while Singapore adopts the higher CAPEX values between Malaysia and Indonesia to reflect its relatively higher development costs.

Fuel price assumptions for coal and gas are based on the International Energy Agency’s World Energy Outlook 2025 under the Stated Policies Scenario (STEPS). Prices are calculated as the average of the European Union, Japan and China values. Milestone year fuel prices for 2035 and 2050 are interpolated exponentially over the remaining modelling years. Biomass fuel cost is assumed to be $32 per tonne in 2024 based on an ERIA report, with an energy content of 17 GJ per tonne and an annual cost escalation of 5%.

All other techno-economic parameters follow the default dataset provided in Scenario Builder documentation. Raw outputs of base case and delay scenarios can be downloaded from the platform.

Limitations

Due to computational constraints, the model contains several limitations. These include an annual 32-time-slice temporal resolution and the exclusion of transmission losses, which can potentially lead to an overestimation of the benefits of long-distance electricity trade. In addition, the analysis is limited to capacity expansion optimisation and does not include chronological economic dispatch modelling. Finally, transmission cost overrun due to delays is also not considered in this study even though it often occurs in practice and could significantly increase the costs of delaying.

Acknowledgements

Contributors

We would like to thank Dr. Priyantha Wijayatung (ADB) and Dr. Victor Nian (CSER) for their quotes on the report. A special thanks to Clem Arlidge (Google APAC) and Isabella Suarez (TransitionZero) for their inputs and peer review. We would also like to extend our gratitude to TransitionZero for the data and technical support with the Scenario Builder tool.

The author would like to thank Ember’s colleagues for their valuable comments and contributions, including Aditya Lola, Dinita Setyawati, Reynaldo Dizon, Neshwin Rodrigues, Matt Ewen, Giang Vu, Tito Das, Shiyao Zhang, Taiki Asato and Ardhi Arsala Rahmani.

Cover image

Beautiful countryside with a power tower and lush green fields under a blue sky.

Credit: C.T. PHAT / Pexels