Southeast Asia is one of the fastest-growing energy markets in the world. Population growth, industrialisation, urbanisation and rising incomes are driving rapid increases in electricity consumption. The region represents nearly 9 per cent of the global population and over 6 per cent of the global GDP, and its energy demand is projected to grow (~4 per cent annually) faster than the global average up to 2050. Several structural factors are pushing electricity demand upward, including expansion of manufacturing and export industries; transport electrification; growth of data centres and digital infrastructure; and expanding middle-class consumption. Meeting this demand while maintaining affordability and reducing emissions poses a major challenge.
Many of the members of the Association of Southeast Asian Nations (ASEAN) rely heavily on imported fossil fuels, particularly coal and natural gas. This dependence exposes the region to fuel price volatility and geopolitical risks. To mitigate this, eight of the eleven ASEAN countries have announced carbon neutrality and net-zero emissions targets, with many already implementing policy measures to scale up renewables, including competitive auctions, direct power purchase agreements (PPAs) and feed-in tariffs. The ASEAN Renewable Long-Term Roadmap (October 2025) provides a comprehensive plan for scaling up renewable energy to meet future demand. The share of renewable energy (including energy storage) in the region’s installed capacity is expected to increase from around 33 per cent in 2023 to around 58-62 per cent by 2045, depending on the considered scenarios. The 2025 renewal of the five-year ASEAN Plan of Action for Energy Cooperation (APAEC) is expected to reinforce the regional commitment to the progressive deployment of renewables until 2030.
Given the dynamic shifts in demand-supply conditions in the region, an interconnected regional grid would enable countries to share electricity resources, reducing the need for each country to maintain costly backup capacity. In this context, the ASEAN Power Grid (APG), one of the region’s most ambitious energy initiatives under pursuit since 1999, aiming to integrate national power systems across Southeast Asia through a network of cross-border transmission lines and coordinated electricity markets, offers multiple strategic benefits, including improved energy security, reduced system costs, enhanced grid reliability, large-scale regional electricity trade and greater flexibility for integrating renewable energy at an accelerated pace. According to regional analyses, electricity integration could also help countries optimise the use of geographically diverse renewable resources, such as hydropower in Laos and northern mainland Southeast Asia, solar potential across the region, particularly Thailand, Vietnam and Indonesia and wind potential in coastal areas and offshore regions.
Building a region-wide transmission network linking the 11 ASEAN countries involves massive investment. A recent International Energy Agency (IEA) report, “Financing the ASEAN Power Grid”, examines how Southeast Asia can mobilise capital on a large scale. The report focuses specifically on financing models, investment barriers and institutional arrangements required to develop cross-border infrastructure. The IEA report argues that while technical feasibility and political commitment are increasingly strong, financing remains the central bottleneck. Delivering the APG will require a substantial increase in investment in the transmission infrastructure and new business models capable of attracting both public and private capital.
ASEAN Power Grid and the scale of investment
The key elements of APG Vision 2045 include cross-border high-voltage transmission lines, subsea interconnections between island systems, regional electricity trading frameworks, and harmonised grid codes and operational standards. ASEAN has 10.2 GW of cross-border capacity (both grid-to-grid and generation-to-grid), partly facilitated by nine operational interconnections out of the 18 priority projects envisioned under the ASEAN Interconnection Masterplan Study (AIMS) III. Several interconnectors aggregating about 16 GW capacity are currently in various planning and development stages, including at least half a dozen subsea high-voltage direct current (HVDC) projects.
AIMS III estimates that USD764 billion will be needed for transmission expansion (cross-border transmission lines, subsea power cables, grid upgrades within countries) and new generation (including battery energy storage system [BESS]) to support high levels of renewable energy. The enhanced APG MoU, signed by the ASEAN countries in October 2025, marks a critical milestone in ASEAN’s ambition to realise a fully integrated, low-carbon regional electricity network by 2045. Developing the APG transmission network alone is expected to require at least USD100 billion by 2045, according to the Asian Development Bank (ADB). As per IEA analyses across three modelled cost scenarios, the total interconnection investment needed to realise the APG’s ambitions is estimated at USD27 billion between 2025 and 2040, in the Base case. This translates to an average annual spending of around USD1.9 billion — roughly 20 times higher than the annual spending levels observed in 2019-24. Annual investment would need to surpass USD1 billion before 2030 and an average of more than USD2 billion per year during the 2031-40 period.
Cost Reduction case – All projects are achieved on time with minimal challenges, keeping overall costs low. The cost of subsea cables and converters increases in the short term but declines in the 2030s as supply chains improve; Base case – All projects are achieved on time with capital expenditures matching expectations based on historical project costs. The cost of subsea cables and converters increases steadily over time due to sustained demand; Cost Overrun case – Various challenges lead to longer construction times and higher capital expenditures. Sustained supply chain constraints drive long-term price inflation for cables and converters.
The transition from bilateral interconnections to a fully integrated regional grid remains a major challenge. The IEA report argues that financing—not technology—is now the primary obstacle to implementing the APG. Large transmission projects have several characteristics that make financing difficult, such as high upfront capital costs, long construction timelines, complex cross-border regulatory arrangements, uncertain revenue streams and coordination across multiple governments. Because of these factors, investors often view regional transmission projects as high-risk infrastructure investments. Conducive conditions are needed to create a portfolio of bankable projects and mobilise capital at scale with participation from governments, utilities, development banks and private investors.
Past financing models and upcoming trends
The historical project landscape is dominated by generation-to-grid connections—mainly hydropower projects in Lao PDR exporting electricity to Thailand and beyond—rather than the grid-to-grid connections envisioned in regional plans. These projects have successfully attracted private and international investment through project finance structures, with independent power producers (IPPs) using build, operate and transfer (BOT) and build, own, operate and transfer (BOOT) models. A major part of the private interconnector investment in ASEAN over the past several decades has been in Lao PDR, reflecting this export model. By contrast, grid-to-grid interconnectors are typically financed on the balance sheets of state-owned enterprises (SOEs), structured as separate projects meeting at the border. So far, no ASEAN country has adopted a joint bilateral project structure—a model common in Europe—where a single shared special purpose vehicle (SPV) spans multiple jurisdictions. The Lao PDR–Thailand–Malaysia–Singapore Power Integration Project (LTMS-PIP), launched in 2022 and expanded in 2024, marks a milestone as ASEAN’s first multilateral power trade. However, it relies on existing infrastructure, has modest capacity (200 MW) and operates through bilateral contracts rather than a unified multilateral framework—making it a pathfinder rather than a scalable template. Nonetheless, as wheeling charges are a key enabler of multilateral power trade in ASEAN, the methodology used for LTMS-PIP serves as an important reference for developing future projects and regional frameworks, such as the proposed Brunei Darussalam, Indonesia, Malaysia and the Philippines Power Integration Project (BIMP-PIP).
According to IEA, two structural shifts make it more challenging than simply scaling up historical models. First, the geographic focus is changing: while 77 per cent of pre-2025 investment was concentrated in Lao PDR and Thailand, these countries account for just 3 per cent of the future pipeline. Instead, Malaysia, Indonesia and Singapore will dominate, reflecting the underdeveloped connectivity in the southern and eastern subsystems and the high costs of subsea links across archipelagic regions.
Second, the technology mix is shifting. Subsea interconnectors – previously rare – are expected to make up over 75 per cent of investment from 2030 onward. These rely on HVDC systems, which require costly converter stations. Four projects in the current pipeline would, if built today, each exceed the length of the 765-km Viking Link — currently the world’s longest operational subsea interconnector. Several individual projects are expected to exceed USD1 billion in total costs. Rising equipment and supply constraints further complicate delivery: prices for cables and transformers have nearly doubled since 2018, while manufacturing capacity and cable-laying vessels are already stretched, increasing the risk of delays and cost overruns.
Financing challenges
Structural and macro-financial barriers include the fiscal constraints of many ASEAN state-owned SOEs, which already carry heavy investment burdens for domestic transmission and distribution. Most ASEAN regulatory frameworks restrict the majority ownership of transmission assets by private or foreign entities on national security grounds, limiting the pool of potential investors. Currency mismatches — in which projects earn revenues in local currencies, but debt is often denominated in USD— create foreign exchange exposure that deters long-term commercial lenders. Country credit ratings and shallow domestic capital markets in some ASEAN economies mean commercial debt is expensive and short-tenured, typically 7-10 years — far shorter than the 20-30-year horizons interconnectors require.
Commercial arrangement challenges stem from a lack of standardised, transparent trading frameworks. Power trade in ASEAN relies on bilateral power purchase agreements negotiated case-by-case basis, with limited standardisation and no regional market mechanism. Diverse market structures and tariff regimes across ASEAN countries— ranging from liberalised markets with cost-reflective tariffs in Singapore and the Philippines, to vertically integrated markets with bundled tariffs in Indonesia and Cambodia — create asymmetries that complicate cost and benefit allocation. Wheeling charges for transit through third-party grids, such as those used in the LTMS-PIP, lack a harmonised methodology, raising the risk of “tariff pancaking” that discourages the very trade, which integration seeks to promote. The Malaysia–Singapore interconnector, despite having a transfer capacity of around 1,000 MW, currently uses only up to 200 MW for commercial exchange — an illustration of how underdeveloped trading arrangements suppress utilisation and undermine project viability.
Project-level bankability challenges arise because revenue streams for interconnectors are unpredictable, especially for grid-to-grid projects where volumes depend on decisions made by utilities controlling electricity despatch. Without availability-based payments that compensate investors regardless of how much electricity flows through the line, interconnectors face acute utilisation risk. The report’s financial modelling shows that at 20 per cent utilisation with no availability payments — comparable to current usage of the Malaysia–Singapore link — equity internal rates of return (IRRs) fall by 12 percentage points relative to a purely availability-based revenue model.
Financing structures and bankability
The IEA report provides a detailed examination of how interconnector projects should ideally be structured to attract different categories of capital. It identifies four key capital providers: SOEs as anchor sponsors; multilateral development banks (MDBs) and export credit agencies (ECAs) for long-tenor debt; infrastructure funds seeking mid-teen equity returns; and institutional investors such as pension funds and sovereign wealth funds as long-term holders.
Financial modelling of a representative HVDC subsea project across three scenarios produces revealing results. Under a supportive Cost Reduction scenario — with concessional debt at 3.5 per cent, high leverage of 70:30 and availability-based payments covering 50 per cent of revenue — equity IRRs reach the high teens to mid-twenties, well within institutional investor appetite. Under the Base case — more realistic ASEAN conditions with 7 per cent debt costs — project IRRs of 10-12 per cent are sufficient for utilities and potentially some institutional investors, but fall short of commercial infrastructure fund targets. Under the Cost Overrun scenario — with expensive commercial debt at 10.5 per cent, no availability payments and construction delays — equity IRRs compress to around 5 per cent, making projects non-bankable for commercial investors.
The sensitivity analysis is unambiguous about which levers matter most: tariff levels and debt pricing dominate. A 10 per cent increase in tariff levels improves equity IRR by approximately 1.6 percentage points; reducing debt cost from 7 per cent to 3.5 per cent and increasing leverage together boost equity IRR by over 5 percentage points. Operational factors such as transmission losses have a comparatively minor impact. The fundamental conclusion is that interconnector viability hinges primarily on policy frameworks and access to affordable capital rather than technical execution.
The report identifies an “equity valley of death” — early-stage investors cannot recycle capital without exit mechanisms that do not currently exist in ASEAN transmission markets. Four pathways forward are proposed within existing regulatory constraints: mobilising capital through blended finance structures, while retaining SOE ownership; establishing revenue certainty through transparent tariff reform with availability payments; deploying concessional and blended finance to address the debt cost gap; and building market infrastructure — through refinancing, project bonds, and secondary sales of minority stakes — to enable capital recycling.
Key priorities for scaling investment
Making the APG a reality will require coordinated action to overcome the challenges, make interconnector projects bankable and catalyse the financing needed to build them. The IEA report’s recommendations are categorised into seven themes:
Embed cross-border projects in national planning. Interconnectors should be integrated into national power development plans, not treated as politically aspirational add-ons. Governments must proactively assess and articulate the economic and social benefits of interconnectors — in terms of cost savings, energy security, job creation and emissions reductions — to build the business case and attract financing. Government leadership during project preparation and permitting is essential to advance development and significantly lower the risk of delay or cancellation.
Establish transparent and harmonised commercial arrangements. Revenue frameworks should be guided by regulation, not bespoke contracts. A harmonised regional methodology for transmission charges and wheeling costs – as demonstrated by the West African Power Pool and Central American Electrical Interconnection System (SIEPAC) – would reduce transaction costs, strengthen investor confidence and improve asset utilisation. Remuneration should capture multiple services provided by the interconnection infrastructure – electricity transmission as the main service provided, as well as the secondary services delivered in terms of grid stability, flexibility, emissions reductions and savings from deferred investment into other solutions for flexibility. Availability-based payments should be adopted as a standard feature. Governments can also blend availability-based payments with utilisation-based charges to balance risk allocation and affordability, reducing fixed payment obligations, while maintaining bankability.
Deploy alternative financing models to attract new sources of capital. Governments should move beyond the split-project SOE model. Joint bilateral SPVs with shared ownership, independent transmission project (ITP) models with third-party developers, and shared ownership structures for projects with regional benefits should all be explored and, where needed, enabled through targeted regulatory reform. ITP models can enable SOEs to raise non-recourse project finance and minority equity from international investors through SPVs, potentially reducing SOE financing requirements across the APG project pipeline.
The region is already exploring one such model through the ASEAN Power Grid Financing Initiative (APGF), launched in October 2025 by the Asian Development Bank, the World Bank, the ASEAN Secretariat and the ASEAN Centre for Energy, to mobilise large-scale funding for both domestic and cross-border transmission projects. The ADB has committed USD10 billion over 10 years, along with USD6 million in technical assistance for project development, capacity building and regional cooperation. The World Bank will contribute USD2.5 billion through its Accelerating Sustainable Energy Transition Program. The initiative will provide a mix of financing tools, including grants, concessional and standard loans, guarantees, political risk insurance, PPP advisory services and equity support.
Mitigate investment risks to lower financing costs and enhance bankability. Reducing the cost of capital and improving bankability for APG projects requires an integrated approach to risk management from the outset. Key risks should be identified early through engagement with technical, insurance and advisory experts and addressed in project design, technology selection, and contractual structuring—especially for complex subsea interconnectors. Risks must be allocated to the parties best able to manage them, while residual risks—such as political or market uncertainties—can be mitigated through guarantees, insurance and credit enhancement tools provided by multilateral and private institutions. Public financing and concessional capital play a crucial role in bridging bankability gaps, particularly for early-stage or high-risk projects, with government backing helping attract private investment. Finally, sharing data and lessons from project performance is essential to improve risk assessment, lower perceived risks and reduce financing costs over time.
Leverage international public finance strategically. It plays a critical role in bridging financing gaps for ASEAN interconnectors by providing concessional, long-tenor funding, where commercial lenders are constrained. Multilateral development banks (MDBs), development finance institutions (DFIs) and export credit agencies (ECAs) help mitigate risks—such as political, currency and credit risks—especially in markets with weaker fundamentals, while also offering local currency financing and credit enhancements. Beyond project financing, they support pipeline development through feasibility studies and technical assistance and can unlock additional capital by recognising interconnectors as enablers of the clean energy transition within climate finance frameworks/taxonomies. Crucially, their involvement helps establish bankable, replicable project models, reduces perceived risks through strong due diligence and enables the gradual entry of private capital, ensuring a transition from public to commercially driven financing over time.
Establish capital recycling mechanisms through structured exit pathways. Sustaining ASEAN’s interconnector pipeline requires recycling early-stage capital, as investors are often unable to exit operational projects, creating an equity valley of death that limits funding for new developments. Addressing this involves pre-structuring clear exit pathways—such as refinancing windows, minority stake sales to institutional investors, and integration into regional investment platforms—so capital can be redeployed efficiently. Governments can support this by embedding refinancing provisions in project agreements, enabling SOEs to sell minority stakes without losing control and establishing regional platforms to create secondary markets for operational assets. Clear regulatory frameworks for equity transactions—including approval processes, valuation methods, tax treatment and investor eligibility—are essential to reduce uncertainty, lower transaction costs and facilitate capital recycling at scale.
Strengthen strategic coordination between utilities, policymakers and equipment suppliers. Meeting ASEAN’s interconnector ambitions requires closer public-private collaboration to strengthen manufacturing capacity and supply chains. Greater transparency in project pipelines and forward planning can reduce uncertainty for equipment suppliers, enabling them to invest in capacity, workforce and raw materials. Utilities can further de-risk delivery by adopting multi-year framework agreements and strategic partnerships to lock in pricing and secure production slots. While full standardisation is not feasible, harmonising procurement frameworks and technical requirements across countries can unlock economies of scale and improve efficiency. At the same time, investing in regional manufacturing, resilient supply chains and workforce development is essential to reduce dependency on external suppliers, manage geopolitical risks and build long-term capability for complex technologies such as subsea HVDC interconnectors.
Conclusion
ASEAN has achieved significant political momentum around energy connectivity, but translating ambition into implementation requires addressing gaps in policy, institutional capacity and financing structures rather than economics, as modelling shows interconnectors can deliver competitive, bankable returns. Critical enablers include tariff certainty, availability-based payments, harmonised commercial frameworks, access to affordable long-tenor debt and credible investor exit pathways. Achieving the investment challenge will demand sustained, coordinated action by governments, regulators, utilities, development finance institutions and the private sector.
Regional grid integration must become a central pillar of Southeast Asia’s energy transition strategies, with governments taking a stronger early-stage role in project preparation, planning and financing. Mobilising private capital will require innovative financing structures—such as PPPs, regulated asset models and blended finance—and robust risk-sharing mechanisms. Multilateral development banks will serve as critical catalysts by providing anchor financing that attracts additional private investment, while strengthened regional governance and electricity market frameworks will ensure long-term success. The APG’s success will hinge not only on infrastructure investment but also on financial innovation, institutional coordination and regional cooperation, enabling Southeast Asia to build one of the world’s largest integrated electricity systems and support both economic growth and the long-term energy transition.