Decarbonizing the Power Sector in East Asia: Unlocking Investments to Empower Low-Carbon Growth and Competitiveness October 2025 © 2025 The World Bank 1818 H Street NW, Washington DC 20433 Telephone: 202-473-1000; Internet: www.worldbank.org Some rights reserved This work is a product of The World Bank. The findings, interpretations, and conclusions expressed in this work do not necessarily reflect the views of the Executive Directors of The World Bank or the governments they represent. The World Bank does not guarantee the accuracy, completeness, or currency of the data included in this work and does not assume responsibility for any errors, omissions, or discrepancies in the information, or liability with respect to the use of or failure to use the information, methods, processes, or conclusions set forth. 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Decarbonizing the Power Sector in East Asia: Unlocking Investments to Empower Low-Carbon Growth and Competitiveness. © World Bank.” Any queries on rights and licenses, including subsidiary rights, should be addressed to World Bank Publications, The World Bank, 1818 H Street NW, Washington, DC 20433, USA; fax: 202-522-2625; e-mail: pubrights@worldbank.org. Cover photos: © Philippe Weickmann / Pexels; © Anna Tukhfatullina / Pexels. Used with permission. Cover design: Gao Feng Contents Acknowledgments..................................................................................................................................... 01 Executive Summary................................................................................................................................... 02 Abbreviations............................................................................................................................................ 06 1. The East Asia and Pacific Region: Energy at a Crossroads....................................................................... 08 1.1 Putting the Region’s Emissions Into Context.............................................................................................. 08 1.2 The Energy Transition’s Role in Improving Regional Energy Security and Relieving Dependence on Coal...... 12 1.3 Key Objectives of this Report...................................................................................................................... 17 1.4 Research Approach and Methodology....................................................................................................... 17 1.5 Analytical Framework.................................................................................................................................. 19 1.6 Market Tiers—VRE Market Maturity.......................................................................................................... 20 2. Renewable Energy Integration in East Asia and Pacific.......................................................................... 23 2.1 The Four Focus Countries Hold Vast Renewable Energy Potential............................................................ 23 2.2 Renewable Energy’s Share of Generation Varies Across the Region......................................................... 25 2.3 Deep Dive into the Focus Countries............................................................................................................ 26 2.4 A Look at the Rest of the Region................................................................................................................. 28 2.5 Drivers of Regional VRE Growth.................................................................................................................. 29 2.6 Renewable Energy Expansion Needed to Fulfill Climate Ambitions.......................................................... 34 3. Barriers to VRE Scale-up in the Focus Countries..................................................................................... 37 Pillar 1. System planning does not adequately account for new drivers of economic growth, distributed generation, VRE integration, and infrastructure resilience.............................................................................. 38 Pillar 2. Policy and regulatory uncertainty limits investor confidence and investments in EAP..................... 39 Pillar 3. Traditional transmission infrastructure and power system operations limit VRE integration.......... 43 Pillar 4. Limited financing and investment constraints hinder the future of energy transition in EAP.......... 45 4. Accelerating VRE Deployment in the Focus Countries............................................................................ 49 Pillar 1. Power market planning needs to be transparent, institutionally aligned, and adequately consider new demand drivers.......................................................................................................................................... 50 Pillar 2. De-risk investments through predictable and transparent tariff frameworks, procurement mechanisms, balanced risk allocation in power purchase agreements (PPAs), and streamlined permitting processes............................................................................................................................................................ 52 Pillar 3. Invest in transmission infrastructure, introduce market participation frameworks for energy storage, and harmonize grid codes for regional trade................................................................................................... 59 Pillar 4. Undertake comprehensive investment planning and syndicate capital requirements through all domestic and international sources.................................................................................................................. 62 Official Use Only References................................................................................................................................................ 64 Appendix A. Other EAP Energy Indicators............................................................................................................. 71 Appendix B. Energy Transition in Non-EAP Countries........................................................................................... 75 Appendix C. Overview of NDC and Power Sector Plan Targets............................................................................ 77 Appendix D. Secondary Barriers to VRE Scale-Up in EAP and Focus Countries................................................... 78 Appendix E. Additional Pathways for Accelerating VRE Deployment in EAP and Focus Countries..................... 82 BOXES Box ES.1 Private Sector Consultations Highlight Project Implementation Challenges in the Focus Countries........ 04 Box 1.1 US Tariffs Offer an Opportunity to Spur the Regional Energy Transition................................................ 15 Box 3.1 Private Sector Feedback: Challenges with China’s Subsidy Program...................................................... 40 Box 3.2 Private Sector Feedback: Challenges with Indonesia’s Renewable Energy Procurement...................... 40 Box 3.3 Private Sector Feedback: Challenges with Vietnam’s PPA Bankability.................................................... 41 Box 3.4 Private Sector Feedback: GEAP Shortcomings in the Philippines............................................................ 42 Box 3.5 Private Sector Feedback: Project Implementation Challenges................................................................ 43 Box 3.6 Global Financial Headwinds are Exacerbating Investment Challenges................................................... 46 Box 3.7 Private Sector Feedback: Challenges with Equity Fundraising in China.................................................. 47 Box 3.8 Assessing Vietnam’s Domestic Credit Capacity for the Energy Transition.............................................. 47 Box 4.1 Germany’s Distributed Generation Strategy for Scaling-up Renewable Energy..................................... 51 Box 4.2 Brazil’s Auction System for VRE Scale-up................................................................................................. 54 Box 4.3 Large-Scale Solar (LSS) Auction in Malaysia............................................................................................. 56 Box 4.4 Streamlining Offshore Wind Permitting Through a One-Stop-Shop in Denmark................................... 57 Box 4.5 Leveraging Government-Owned Land to Expedite Large-Scale Solar Projects in India.......................... 58 Box 4.6 Nord Pool—Using Regional Power Trade for Energy Security................................................................. 60 Box 4.7 Catalyzing Private Investments in Transmission Infrastructure in Brazil................................................. 61 FIGURES Figure 1.1 Energy-related GHG Emissions in the Four Focus Countries, 1990–2022.......................................... 08 Figure 1.2 Energy-related CO2 Emissions, by Sector, in Focus Countries, 2022................................................... 09 Figure 1.3 GHG Emissions from Coal Combustion in Focus Countries, 1990–2022............................................ 09 Figure 1.4 Average Age of Coal-fired Power Plants in Focus Countries, by Size.................................................. 10 Figure 1.5 Select Economies’ Share of Global Coal Consumption, 2023............................................................. 10 Figure 1.6 Coal Exports from Australia and Indonesia, by Destination Country.................................................. 11 Figure 1.7 Grid Emission Factors in the Four Focus Countries, Select Comparators, and the World, 2001–22........ 12 Figure 1.8 Recent and Forecasted Power Sector Generation in the Four Countries, 2015–60........................... 12 Figure 1.9 GHG Emission Projections in the BAU Scenario................................................................................... 13 Figure 1.10 Monthly Coal Prices in Australia, January 2021–November 2024 (US$/metric ton)....................... 13 Figure 1.11 Four Focus Countries’ Ranking on the Notre Dame Global Adaptation Initiative Country Index, 2023..... 14 Figure 1.12 Solar and Onshore Wind LCOE........................................................................................................... 15 Figure 1.13 A Graphic Outline of the Report’s Analytical Framework................................................................. 19 Figure 1.14 Market Tiers and Their Characteristics.............................................................................................. 21 Figure 2.1 Renewable Energy Potential in Focus Countries.................................................................................. 23 Figure 2.2 Untapped Renewable Energy Potential in the Focus Countries (% and GW)..................................... 24 Figure 2.3 Renewable Energy Generation Potential and Projected Generation (TWh)....................................... 25 Figure 2.4 Renewable Energy’s Share of the Electricity Generation Mix, 2022................................................... 26 Figure 2.5 Installed Capacity and Generation Mix in China, 2015–22................................................................. 26 Figure 2.6 Installed Capacity and Generation Mix in Indonesia, 2015–23........................................................... 27 Figure 2.7 Installed Capacity and Generation Mix in Vietnam, 2015–23............................................................. 27 Figure 2.8 Installed Capacity and Generation Mix in the Philippines, 2015–23.................................................. 28 Figure 2.9 Installed Capacity and Generation Mix in the Rest of EAP, 2015–22.................................................. 28 Figure 2.10 Analytical Framework—Pillars Supporting Renewable Energy Growth............................................ 29 Figure 2.11 Ceiling Tariff Ranges............................................................................................................................ 31 Figure 2.12 GEAP 1 Auction Capacities and Awarded Prices, June 2022............................................................. 32 Figure 2.13 GEAP 2 Auction Capacities and Awarded Prices, July 2023.............................................................. 32 Figure 2.14 Renewable Energy Capacity Growth Required in China.................................................................... 34 Figure 2.15 Renewable Energy Capacity Growth Required in Indonesia............................................................. 35 Figure 2.16 Renewable Energy Capacity Growth Required in Vietnam............................................................... 36 Figure 2.17 Renewable Energy Capacity Growth Required in the Philippines..................................................... 36 Figure 3.1 Additional Investments—Generation and Network, 2020–40............................................................ 47 Official Use Only Figure B4.2.1 Brazil’s Installed Capacity, 2000–23................................................................................................ 55 Figure B4.2.2 Solar PV Auction Price Trends in Brazil........................................................................................... 55 Figure B4.3.1 Danish Energy Agency and Key Entities.......................................................................................... 58 Figure A.1 Total GHG Emissions by Region............................................................................................................ 71 Figure A.2 EAP—GHG Emissions by Sector, 1990–2023....................................................................................... 72 Figure A.3 Power Sector Emissions AAGR and Share of Total Emissions............................................................. 72 Figure A.4 GDP/Capita (thousands at 2015 US$ constant), 2001–23................................................................... 74 Figure A.5 Electricity Consumption (MWh/capita), 2001–22............................................................................... 74 Figure B.1 Countries Whose VRE Share in Generation Exceeds 30 Percent, 1999–2023.................................... 76 Figure B.2 VRE Transition (10–30%) Time Frame and GNI.................................................................................... 76 Figure D.1 Focus Countries: LCOE Breakdown...................................................................................................... 81 TABLES Table ES.1 Recommendations for Scaling Up VRE in the Focus Countries........................................................... 05 Table 2.1 Summary of Renewable Energy Targets................................................................................................ 30 Table 3.1 Summary of Barriers to VRE Scale-up in EAP........................................................................................ 37 Table 4.1 Summary of Recommendations for Accelerating VRE Deployment..................................................... 49 Table 4.2 Key Recommendations for Accelerating VRE Deployment in the Focus Countries............................. 57 Table A.1 Energy Intensity/GDP (MJ/thousand 2015 US$)................................................................................... 73 Table C.1 Climate and Renewable Energy Targets................................................................................................. 77 Table D.1 Indonesia—Policy Mismatch.................................................................................................................. 78 Acknowledgments 01 Acknowledgments The World Bank team responsible for the analytical work behind this report was led by Chiara Rogate (Senior Energy Specialist) and Xiaodong Wang (Lead Energy Specialist), with the support of Christianna Ioannou (Energy Consultant), Soyoun Jun (Program Assistant), and Myoe Myint (Senior Energy Specialist). The team is grateful for the valuable country and regional specific inputs provided by Claudia Vasquez (Practice Manager), Zayra Romo (Lead Energy Specialist), Bipul Singh (Senior Energy Specialist), Feng Liu (Senior Energy Specialist), Shinya Nishimura (Senior Financial Specialist), and the cross-collaboration with Yuge Ma (Senior Energy Specialist), Zhuo Cheng (Senior Carbon Finance Specialist), and Priyank Lathwal (Energy Specialist). The work was conducted under the guidance of Jie Tang (Practice Manager, Energy, East Asia and Pacific). The team appreciates the valuable technical comments received by peer reviewer Chandrasekar Govindarajalu (Practice Manager, ESMAP) under the overall technical leadership of Sudeshna Ghosh Banerjee (Regional Practice Director) and Demetrios Papathanasiou (Global Director). The study was prepared with the support of the World Bank–contracted EY Singapore team, led by Sonal Agrawal and Gilles Pascual. The preparation of this report was cofunded by the World Bank Korea Office Trust Fund. Official Use Only 02 Executive Summary Energy-related greenhouse gas emissions are on the rise in the East Asia and Pacific (EAP) region. In China, Indonesia, Vietnam, and the Philippines—the four countries analyzed most closely in the present report—such emissions increased by more than 350 percent between 1990 and 2022, from 2.79 to 12.58 gigatons of carbon dioxide equivalent (GtCO2e). Notably, this last figure, from 2022, surpasses the average magnitude of emissions from the Organisation for Economic Co-operation and Development (OECD) economies that same year. This rise in energy-related emissions is mainly due to the power and industrial sectors. Driving socioeconomic progress, the industrial sector plays a crucial role in propelling the economic development of emerging EAP economies. Meanwhile, a growing population, rising standards of living, and widespread electrification mean more demand for power—and greater emissions from the power sector. Taken together, CO2 emissions from the industrial and power sectors in the four study countries roughly amounted to 10 Gt in 2022. Electricity generation in the four countries continues to rise and is expected to increase by another 25 percent to reach nearly 12,600 terawatt-hours (TWh) by 2030 (from about 10,200 TWh in 2023). Based on national power and electricity plans and World Bank assessments, this trend is expected to continue. Electricity generation is forecasted to climb to more than 20,000 TWh by 2050, and 23,000 TWh by 2060. Rising GDP levels in the EAP are contributing to an increase in electricity demand; electricity consumption per capita growth nearly matched or outpaced GDP per capita growth in the focus countries between 2001 and 2023. The recent increase in electricity demand has disproportionately been met by coal-fired generation. Across the four study countries, over 37 percent of coal plants (by capacity) are less than 10 years old, and 85 percent are less than 20 years old. Considering that the average coal plant lasts 50 years, the focus countries are home to one of the youngest coal fleets in the world. Meanwhile, they account for roughly 60 percent of the world’s coal consumption. EAP’s endowment of domestic coal reserves contributes to the reliance on coal-fired generation. Indonesia and Australia collectively export nearly 875 million metric tons of coal, of which nearly 620 million are traded within the EAP. In China, home to the world’s fourth-largest coal reserves, low-cost coal drove the rapid industrialization of the past three decades. At the same time, coal’s prominence in generation has left net importers like Vietnam and the Philippines exposed to supply disruptions and commodity price shocks. Electricity grids backed by coal are necessarily carbon-intensive. As of 2022, the grid emission factors for all four countries were higher than both global and OECD averages. EAP’s susceptibility to climate-related hazards will test the stability and resilience of the power sector. The 2023 droughts in northern Vietnam caused 11 hydropower stations to shut down, resulting in extended blackouts. Typhoon Rai in the Philippines destroyed power infrastructure and left more than 3 million people without power (which in some areas took weeks to restore). In China’s Sichuan Province, where hydropower supplies 80 percent of electricity, prolonged droughts in 2022 triggered widespread blackouts and factory shutdowns. Advancing the transition to clean energy can help the region balance the energy trilemma of ensuring security, affordability, and sustainability. Power systems in the region are fragile and exposed to climate hazards and commodity price fluctuations. A more diversified energy mix that harnesses domestic renewable energy potential can help shield the region from commodity price shocks and infrastructure disruptions. Executive Summary 03 The EAP region possesses ample renewable energy potential—the four countries under study here are endowed with nearly 65,000 gigawatts (GW) of clean energy capacity. All four countries benefit from a vast solar energy potential, totaling just over 50,000 GW. Indonesia and the Philippines, located on the Pacific Ring of Fire, also have geothermal resources. Vietnam has extensive offshore wind energy potential along its extensive coastline (of more than 3,000 km). The Philippines is also home to around 178 GW of offshore wind energy potential. China’s long coastline and favorable conditions in the northern region provide a combined wind energy potential of more than 11,000 GW. A sizeable agricultural sector in China also offers ample opportunity to convert agricultural waste into energy. While renewable energy deployment in the focus countries has advanced, thanks to regulatory and policy support, progress remains uneven. China leads the world in variable renewable energy (VRE) capacity additions. In 2024, its installed solar and wind capacity surpassed 1,400 GW, supported by a strong domestic manufacturing base. In Vietnam, generous feed-in tariffs played a key role in promoting VRE; as of 2024, solar and wind constituted over 25 percent of the nation’s installed capacity. The Philippines saw its VRE capacity rise to more than 2 GW as of 2023. Meanwhile, Indonesia has struggled with VRE deployment, with less than 1 GW of capacity in operation as of 2023. Consequently, China and Vietnam have much higher VRE shares in their generation mix (China had more than 15 percent in 2023 and Vietnam, about 13 percent in 2024) compared with Indonesia (under 1 percent in 2023) and the Philippines (under 3 percent in 2023). Although the Philippines has a low renewables share, renewable energy auctions have been enabling steady progress, with more capacity expected to come online in the coming years. All focus countries need to ramp up renewable energy deployment to meet their national net-zero targets. The largest capacity additions must come from VRE in each of the focus countries. This includes China, which needs to add 10,800 GW by 2060, increasing from 1,400 GW in 2024. Indonesia must reach 900 GW by 2050, up from less than 1 GW in 2023. Vietnam should aim for 600 GW by 2050, rising from 22 GW in 2023, while the Philippines targets 350 GW by 2050, starting from 2 GW in 2023. According to World Bank assessments, China, even after achieving its 2030 VRE goals six years early, needs to deploy renewable energy capacity— covering hydropower and bioenergy—at an annual rate of more than 270 GW in 2024–60 to reach net zero. Similarly, modeling studies from other international organizations show that renewable energy additions in the other focus countries need to accelerate sharply before 2050 to meet net zero targets. This would require Indonesia to add 38 GW, Vietnam 22 GW, and the Philippines just over 13 GW per year. Inadequate power system planning hinders rapid renewable energy deployment across EAP markets. Power systems in EAP face planning risks because they do not properly consider new demand drivers like industrial decarbonization and the need for investments in network upgrades and infrastructure resilience, including generation, transmission, distribution, and ancillary services. This oversight makes the system vulnerable to problems with expanding and integrating variable renewable energy (VRE). Achieving these ambitious renewable energy targets requires a solid power system planning strategy. A lack of clear, transparent, and predictable tariff frameworks and procurement mechanisms in the focus countries continues to hinder the scale-up of renewable energy deployment. To build interest among investors, the focus countries will have to design and implement competitive auction frameworks with standardized and bankable PPA terms, along with predictable auction schedules and predefined procurement targets. Confidence in developers and financiers will have to be built through improved risk allocation mechanisms, such as indexed tariffs, curtailment compensation, and government-backed guarantees where appropriate. Investments in renewable generation capacity alone will not suffice; transmission infrastructure needs to be strengthened to accommodate more VRE—through grid modernization and the provision of ancillary services. Power grids in the focus countries are built for centralized and dispatchable fossil-fuel-based power generation. As VRE capacity increases, renewable energy generation often has to be reduced because of grid limitations. The potential of energy storage to enhance grid flexibility for VRE capacity is yet to be tapped, and would require adequate pricing mechanisms for ancillary services. Official Use Only 04 In addition to a supportive policy landscape, decarbonizing the power sector in the focus countries would require the mobilization of capital and channeling of investments at an unprecedented scale. Under the World Bank’s Accelerated Decarbonization Scenario 2040, the power sector in the focus countries requires approximately US$9 trillion in capital investments in new assets, roughly 40 percent higher than the investment requirements under existing policies (undiscounted terms). Expertise and product capabilities from domestic financial markets must be incorporated, with support from international financial markets and blended finance instruments, for capital to be an enabler and not a bottleneck to the deployment of decarbonization solutions. Box ES.1 Private Sector Consultations Highlight Project Implementation Challenges in the Focus Countries In China, despite the phase-out of subsidy programs, legacy projects have been impacted by delayed payments, impacting projects’ internal rate of return. Domestic content requirements have also created cost disadvantages for foreign investors. In China, equity fundraising faces challenges, as requirements exceed conventional debt-financing standards. In Indonesia , developers are held back by uncertainties in the procurement process and PLN’s mandatory ownership requirements for renewable energy tenders—requiring its subsidiaries to hold 51 percent stake in project companies. In Vietnam, lack of clarity on the tariff framework and levels, along with shortcomings in the template power purchase agreements for variable renewable energy, hinder access to international project finance. Small developers in the Philippines have highlighted performance bond requirements as a hurdle to participation in the Green Energy Auction Program (GEAP). Permitting and land acquisition barriers exist across the region, but their severity varies by domestic contexts. Distributed renewable energy (DRE) offers a real opportunity to scale up VRE capacity, without burdening the transmission infrastructure. Power sector planning in the region often overlooks the full potential of distributed generation—with development usually focused on large-scale utility projects. By unlocking solar installations on building rooftops and unused land, streamlining the permitting and approval process and enabling sales of excess power to the grid can boost DRE growth and, importantly, increase the take-up of VRE in remote islands across Indonesia and the Philippines. Widespread deployment of battery storage assets and their use in provisioning of ancillary and grid flexibility services is essential. With VRE capacity exceeding 1,400 GW in China, battery storage systems are critical components to manage generation variability, balance power supply and demand, and cost-effectively maintain power system reliability. At the same time, in markets like Vietnam, the Philippines, and Indonesia, where VRE capacity additions are bound to accelerate, investments in battery storage systems must keep pace and follow closely with increases in VRE generation. The establishment of enabling regulatory frameworks to incentivize energy storage deployment (such as capacity payments) and their participation can create a conducive environment for VRE additions. Regional power trade can unlock the energy transition and enhance energy security across the EAP region. An integrated regional market will foster cooperation among markets and help resource-rich regions drive the regional energy transition forward. Coordinated power system planning—both generation and network—is a prerequisite for regional trade. Regional institutions like the Association of Southeast Asian Nations (ASEAN) will be instrumental in driving the harmonization of grid codes and alignment of regulatory frameworks, Executive Summary 05 ensuring that member states follow minimum technical, design, and operational standards to ensure reliability of the interconnected power system. At a minimum, this grid code harmonization should be developed on cross-border interconnectors to facilitate operations across borders. Furthermore, developing a methodology to support transparent import and export price frameworks and common wheeling charges for multilateral power trading is important, with countries engaged in power wheeling adequately compensated for future infrastructure development. This report presents strategic recommendations for VRE scale-up in the EAP region and each of the four focus countries (table ES.1). Table ES.1 Recommendations for Scaling Up VRE in the Focus Countries Market Recommendations - Develop comprehensive power system planning strategies aligned with structural changes in electrification demand, distributed renewable energy targets and development, and requirements for the integration of variable renewable energy (VRE). - De-risk VRE investments through transparency and predictability in procurement procedures and tariff frameworks, and standardize power purchase agreement templates. East Asia - Invest in transmission network upgrades, develop ancillary services, scale up battery and Pacific storage and capacity reserve markets, and harmonize the regional power trade framework (grid code alignment). - Optimize the role of public, private, and concessional finance to reduce the weighted average cost of capital, and spearhead the development of voluntary compliance carbon markets. - Develop an ancillary services and capacity reserve market to scale up energy storage. China - Encourage cross-provincial power system planning for interregional trade. - Introduce generation flexibility through transparent economic dispatch. - Adopt large-scale transparent auctions with a predictable timetable to attract private sector investors and meet national targets. Indonesia - Focus on investment in the capacity and flexibility of transmission and distribution networks to absorb additional VRE integration (e.g., smart grids and energy storage). - Provide policy certainty by establishing a transparent and predictable tariff framework and procurement mechanism for VRE to restore market confidence. Vietnam - Invest in transmission infrastructure upgrades to improve grid integration. - Enhance power purchase agreement bankability to attract private sector investments. - Optimize the role of public and private sectors in transmission and grid infrastructure upgrades. - Reform the scope of the energy virtual one-stop shop (EVOSS) for a streamlined permitting process. Philippines - Refine renewable energy auction design and requirements (e.g. performance bonds). - Enable a fully competitive, contestable retail market by fully operationalizing the Retail Competition and Open Access (RCOA) framework and broadening access to direct renewable energy procurement. Official Use Only 06 Abbreviations AAGR average annual growth rate ADS Accelerated Decarbonization Scenario ANEEL Brazilian Electricity Regulatory Agency ASEAN Association of Southeast Asian Nations BNDES Brazil’s development bank CES Clean Energy Scenario CPS Current Policy Scenario DEA Danish Energy Agency DOE Department of Energy EAP East Asia and Pacific EDGAR Emissions Database for Global Atmospheric Research EJ exajoules ERC Energy Regulatory Commission EREA Electricity and Renewable Energy Authority EU ETS European Union’s Emission Trading Scheme EVN Electricity Vietnam EVOSS Energy Virtual One-Stop Shop FDI foreign direct investment FiTs feed-in tariffs gCO2 grams of carbon dioxide GDP gross domestic product GEAP Green Energy Auction Program GHG greenhouse gas GNI gross national income GtCO2e gigatons of carbon dioxide equivalent GW gigawatts IEA International Energy Agency IPP independent power producer IRENA International Renewable Energy Agency KEN Indonesia’s National Energy Policy kWh kilowatt-hour Abbreviations 07 Lao PDR Lao People’s Democratic Republic LCOE levelized cost of energy LSS Malaysia’s Large-Scale Solar program MEMR Ministry of Energy and Mineral Resources MJ megajoule MOIT Ministry of Industry and Trade MWh megawatt-hour NDC Nationally Determined Contribution ND-GAIN Notre Dame Global Adaptation Initiative Country Index NGCP National Grid Corporation of the Philippines NLDC National Local Dispatch Centre OECD Organisation for Economic Co-operation and Development PEP Philippine Energy Plan PLN Indonesia’s state electric utility company (Perusahaan Listrik Negara) PPA power purchase agreement PR Presidential Regulation RCOA Retail Competition and Open Access framework ROW right of way RPDP8 Vietnam’s Revised Power Development Plan 8 RPS Renewable Portfolio Standards RUEN Indonesia’s National Energy General Plan RUKN Indonesia’s National Electricity Plan RUPTL Indonesia’s Electricity Supply Business Plan (Rencana Usaha Penyediaan Tenaga Listrik) SBV State Bank of Vietnam SIS system impact studies SOEs state-owned enterprises TWh terawatt-hours VAT value added tax VCM voluntary carbon market VRE variable renewable energy Official Use Only 08 TheEast 1.The 1. Asia EastAsia and and Pacific Pacific Region: Region: Energy Energy at a at a Crossroads Crossroads 1.1 Putting 1.1 Putting the the Region’s Region’s Emissions Emissions Into Context Into Context Greenhouse gas Greenhouse (GHG)emissions gas (GHG) emissions from from energy energy generation generation use andare and use onare theon risethe riseEast in the in the East Asia and Asia Pacific and Pacific (EAP) (EAP) region—driven region—driven by China, by China, Indonesia, Indonesia, Vietnam, andVietnam, and the the Philippines Philippines (the four “focus (the four “focus countries” of this countries” report). These fourreport) of this . These countries’ four countries’ energy-related energy-related GHG emissions GHG increased by emissions more thanincreased 350 percent bybetween more than 1990 350 and percent between 2022, from 2.79 to1990 12.58and 2022, from gigatons 2.79dioxide of carbon to 12.58 gigatons(GtCO equivalent of carbon dioxide equivalent 1 2e) (figure 1.1; IEA 2024a). (GtCO 2e) For the (figure first 1.1; time, IEA 2024a). in 2022, 1 For the emissions their combined in 2022, their first time,exceeded thosecombined emissions of the economies exceeded of the those Organisation for Economic of Co-operation the economies of theand Development Organisation (OECD), for where Economic energy emissions Co-operation and declined, Developmentthough marginally, (OECD), wherefrom 11.73 to energy 11.63 GtCO emissions 2e over the declined, period. samemarginally, though from 11.73 to 11.63 GtCO2e over the same period. Figure 1.1 Energy-related GHG Emissions Figure 1.1 Energy-related GHGin Focus the Fourin Emissions Countries, the Four 1990–2022 Focus Countries, 1990–2022 14,000 12,000 10,000 8,000 Mt CO2e 6,000 4,000 2,000 0 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 China Indonesia Vietnam Philippines Source: International Energy Agency. Source: International Note: GHG Energy = greenhouse Agency. gas. Note: GHG = greenhouse gas. Therapid The rapid growth energy-relatedemissions growth of energy-related emissionsinin the the focus focus countries countries was was primarily primarily driven driven bypower by the the power and industrial sectors. Industrial expansion, population growth, higher living standards, and and industrial sectors. Industrial expansion, population growth, higher living standards, and widespread electrification widespread are exerting are electrification pressure on the exerting poweron pressure sector, while industry the power remains sector, while centralremains to socioeconomic industry central development. Both industry and power generate significant CO emissions. Electricity to socioeconomic development. Both industry and power2 generate significant CO2 emissions. and heat accounted for roughly Electricity 45–57 and heatpercent of all accounted energy-related for roughly 45–57CO2 emissions percent in 2022, of all and industry-related energy-related emissions CO2 emissions close in 2022, to 30 percent in China, Indonesia, and Vietnam—and 11 percent in the Philippines, an outlier (figure 1.2). and industry-related emissions close to 30 percent in China, Indonesia, and Vietnam—and 11 percent Taken together, the emission shares of electricity/heat and industry are substantially higher than in the OECD in the Philippines, an outlier (figure 1.2). Taken together, the emission shares of electricity/heat and economies, where they are 35 and 19 percent, respectively. industry are substantially higher than in the OECD economies, where they are 35 and 19 percent, respectively. Figure 1.2 Energy-related CO2 Emissions, by Sector, in Focus Countries, 2022 1 Refer to appendix A for details on EAP’s other power sector indicators. 1 Refer to appendix A for details on EAP’s other power sector indicators. Official Use Only Energy at a Crossroads 09 Figure 1.2 Energy-related CO2 Emissions, by Sector, in Focus Countries, 2022 12000 100% 12000 100% 90% 10000 90%80% 10000 Others 80%70% 8000 Commercial & Public Others 70%60% Residential 8000 Commercial & Public Mt CO2e 6000 60%50% Transport Residential Mt CO2e Industry Transport 6000 50%40% Electricity & Heat Industry 4000 40%30% Share& Electricity Electricity Heat & Heat 4000 30%20% Share Share Industry Electricity & Heat 2000 20%10% Share Industry 2000 0 10%0% China Indonesia Vietnam Philippines 0 0% China Indonesia Vietnam Philippines Source: International Source: Energy International Agency. Energy Agency. Note: Note: Mt COMt =CO 2 = million million metric metric tons tons of carbon of carbon dioxide dioxide equivalent. equivalent. Source: International Energy Agency. 2 The Note: region’s Mt CO energy-related 2 = million emissions metric tons of carbon dioxide are closely linked to coal use. Between 1990 and 2022, GHG equivalent. The region’s Theemissions energy-related emissions from coal combustion region’s energy-related emissions are closely in the are focus linked closely to coal countries linked toincreased coal Between use.use. by more Between1990 and386 than 1990 2022, emissions GHG GHG andpercent—from 2022, from coal combustion 1.86 emissions tofrom 9.06coal GtCO in the focus countries combustion increased 2e (figure 1.3)—associated in the focus countriesby more with a shiftthan increased 386 toward percent—from coal-fired by more than 386 1.86Installed to 9.06 GtCO power. percent—from coal 2e (figure 1.86 1.3)—associated capacity to 9.06 continues GtCO2e (figurewith a to grow: shift toward coal-fired more than 37 percent 1.3)—associated power. with aof Installed coaltoward shift plants (bycoal capacity capacity) coal-fired continues are under power. to grow: 10 years Installed coal more old, than 37 percent and capacity 85 of coal percent continues are to plants under grow: (by 20 capacity) more (figure than 37 are 1.4; under GEM percent of10 2025). coalyears Givenold, plants an and (by 85 percent average capacity)coal plant’s are are under under 20 (figure approximate 10 years 1.4; old,50- 2025). GEM year Given lifespan, an the average focus20 coal countriesplant’s approximate 50-year lifespan, the focus countries host one of the and 85 percent are under (figure host one of 1.4; GEM the youngest 2025). Given an coal fleetscoal in the average world. plant’s approximate 50- youngest coal fleets in the world. year 1.3 the lifespan, Figure GHG focus countries Emissions from host Coalone of the youngest Combustion in Focuscoal fleets in the Countries, world. 1990–2022 Figure 1.3 GHG Emissions Figure from 1.3 GHG Coal Combustion Emissions in Focus Countries, from Coal Combustion in Focus 1990–2022 Countries, 1990–2022 10,000 9,000 10,000 8,000 9,000 7,000 8,000 6,000 7,000 Mt CO2e 5,000 6,000 Mt CO2e 4,000 5,000 3,000 4,000 2,000 3,000 1,000 2,000 1,000 0 1991 1990 1992 1991 1993 1992 1994 1993 1995 1994 1996 1995 1997 1996 1998 1997 1999 1998 2000 1999 2001 2000 2002 2001 2003 2002 2004 2003 2005 2004 2006 2005 2007 2006 2008 2007 2009 2008 2010 2009 2011 2010 2012 2011 2013 2012 2014 2013 2015 2014 2016 2015 2017 2016 2018 2017 2019 2018 2020 2019 2021 2020 2022 2021 2022 0 1990 China Indonesia Vietnam Philippines China Indonesia Vietnam Philippines Source: International Energy Agency. Source: International Note: Energy Agency. GHG = greenhouse gas; Mt CO2 = million metric tons of carbon dioxide equivalent. Source: International Energy Agency. Note: GHG = greenhouse gas; Mt CO2 = million metric tons of carbon dioxide equivalent. Note: GHG = greenhouse gas; Mt CO2 = million metric tons of carbon dioxide equivalent. Figure 1.4 Average Age of Coal-fired Power Plants in Focus Countries, by Size Figure 1.4 Average Age of Coal-fired Power Plants in Focus Countries, by Size Official Use Only Official Use Only Official Use Only 10 700 Figure 1.4 Average Age of Coal-fired Power Plants in Focus Countries, by Size 600 700 500 600 400 GW 500 300 400 GW 200 300 100 200 0 100 0-9 years 10-19 years 20-29 years >30 years 0 China Indonesia Vietnam Philippines 0-9 years 10-19 years 20-29 years >30 years Source: Global Energy Monitor. China Indonesia Vietnam Philippines Note: GW Source: = gigawatts. Global Energy Monitor. Note:Source: Global Energy Monitor. GW = gigawatts. result As aNote: GWof this relatively young and extensive coal fleet, EAP countries accounted for nearly 60 = gigawatts. percent As a As of result ofthe a resultthisworld’s of coal relatively consumption young this relatively extensive and and young 2023 in coal extensive (figure fleet, coal EAP1.5; fleet, IEA countries EAP data). accounted countries Global coal for accounted for consumption nearly 60 percent nearly 60 increased of the from 93 exajoules (EJ) percent of the world’s coal consumption in 2023 (figure 1.5; IEA data). Global coal consumption coal world’s coal consumption inin 2000 2023 to (figure164 EJ 1.5; in IEA 2024—a data). jump Global of coal 71 EJ—led consumption by EAP, where increased from 93 consumption exajoules (EJ) in increased jumped 2000 from to 93 by 88 164 EJ in(surpassing EJ exajoules 2024—a (EJ) jump in 2000 the to global of 164 71 in total EJ EJ—led due by 2024—a EAP, jump to where consumption of 71coal declines consumption EJ—led elsewhere). jumped by EAP, where coalby 88 EJ (surpassing the global consumption jumped total due by 88 EJto consumption (surpassing the declines elsewhere). global total due to consumption declines elsewhere). Figure 1.5 Select Economies’ Share of Global Coal Consumption, 2023 Figure 1.5 Select Economies’ Figure Share 1.5 Select of Global Economies’ Coal Consumption, Share of Global Coal 2023 Consumption, 2023 Rest of the Rest of world the 18.9% world 18.9% India India 12.5% China 12.5% China 53.8% 53.8% US US EUEU 6.6% 6.6% 4.2% 4.2% Philippines Philippines 0.5% 0.5% Indonesia Indonesia Vietnam Vietnam 2.0% 2.0% 1.3% 1.3% Source: International Energy Agency. Source: Source: Energy Agency. International Energy International Agency. Note: EU = European Union; US = United States. Note: EU= Note: EU =European Union; US European Union; US = United States. = United States. Coal consumption is intricately connected to EAP’s domestic endowment of resources. China is consumption Coalconsumption Coal is intricately is intricately connected connected to EAP’sto domestic EAP’s domestic endowment endowment of resources. of resources. China is home China is to the home to the fourth largest coal reserves in the world, and coal was instrumental in driving the home fourth to the largest country’s fourth coal largest reserves economic in the growth. The reserves coal world, and coal low cost ofincoal thepower was world, instrumentaland in coal generation was driving has instrumental the been a key factorin in driving country’s economic China’s the growth. The low cost country’s of coal power economic generation growth. The hascost low been a coal of key factor power in China’s economic generation has competitiveness, been a key factor driving rapid in China’s economic competitiveness, driving rapid economywide industrialization and establishing its status as economywide economic industrialization competitiveness, and establishing driving rapidThese its status economywide as a global manufacturing industrialization and powerhouse. establishing These its statuscoal as a global manufacturing powerhouse. coal reserves have played a crucial role in ensuring reserves a global have played manufacturing a crucial role in powerhouse. ensuring Thesenational coal ofenergy reserves security, allowing for the creation of a largely national energy security, allowing for the creation a largely have played self-reliant a crucial power sector.role in ensuring In Indonesia, largeenergy national security, coal reserves haveallowing not onlyfor the creation supported of a largely the nation’s self-reliant economic growth power sector. In Indonesia, and competitiveness but large coal reserves have not only supported the nation’s economic growth and competitiveness but Official Use Only Official Use Only Energy at a Crossroads 11 self-reliant power sector. In Indonesia, large coal reserves have not only supported the nation’s economic growth and competitiveness but have also generated significant revenue through exports, particularly to other Asia-Pacific markets. Coal power generation in Indonesia was further incentivized by the domestic market policy, obligation have which also mandated generated a portion significant of coal revenue production through exports, to be sold at particularly toaother capped price. markets. Asia-Pacific Coal power generation in Indonesia was further incentivized by the domestic market obligation policy, Indonesiawhich and Australia mandated a collectively export portion of coal nearly production to 875 million be sold metric at a capped tons (Mt) of coal,2 the majority of price. which—nearly Mt—is 620 and Indonesia traded Australia within the collectively EAP. export China nearly is million 875 the largest metricexport destination tons (Mt) for of coal,2 the Indonesia (218 majority Mt) and the second-largest for Australia (56 Mt). Philippines and Vietnam import of which—nearly 620 Mt—is traded within the EAP. China is the largest export destination roughly Mt of coal 77 for from Australia and Indonesia, Indonesia (218 Mt) and theIndonesia with importing also for second-largest Australianearly 6 Mt (56 Mt). from Australia. Philippines The focus and Vietnam import countries collectively account roughly for of 77 Mt coal from coal a regional trade Australia volume and of 356 Indonesia, with Mt, or 40 percent Indonesia of the also importing commodity nearly 6 Mt fromflow in the Australia. region. Australia andThe focus countries Indonesia collectively also export account volumes substantial for a regional coal trade to non-EAP volume of markets 356 Mt, (figure or particularly 1.6), 40 percent India, Pakistan, of the and commodity flow Bangladesh, whilein the region. other EAPAustralia markets and Indonesia account foralso onlyexport aboutsubstantial 18 Mt, or volumes 2 percent, of trade. markets (figure 1.6), particularly India, Pakistan, and Bangladesh, while other EAP markets to non-EAP regional coal account for only about 18 Mt, or 2 percent, of regional coal trade. Figure Figure 1.6 1.6 Coal Coal from Exports Exports Australia from and Australia and Indonesia, Indonesia, by Country Destination Country by Destination China Indonesia Indonesia Japan Malaysia Non-EAP Other Asia Other-EAP Australia Philippines Rep. of Korea Thailand Vietnam 0 100 200 300 400 500 600 Million Metric Tons Source: UN Comtrade. Source: UN Comtrade. Note: EAP = East Asia and Pacific. Note: EAP = East Asia and Pacific. disproportionately ReflectingReflecting high coal disproportionately use, high coalthe focus use, countries’ the focus electricity countries’ grids electricity are grids more are morecarbon carbonintensive than global and OECD averages. From 2001 to 2022, only China could reduce its grid intensive than global and OECD averages. From 2001 to 2022, only China could reduce its grid emission factor (from 873.1 to 588.7 emission grams factor of carbon (from 873.1dioxide to 588.7per kilowatt-hour grams [gCO of carbon dioxide 2/kWh]), per thanks kilowatt-hour to 2greater [gCO integration of /kWh]), thanks renewables, although to greater it remains integration of higher the OECD than although renewables, it average remains higher gCO2 (321.7than /kWh) the OECD oraverage global average (321.7 (460.4 gCO2/kWh) gCO 2/kWh) (IEA or global 2024b). Grid average emission (460.4 2/kWh) gCOfar factors 2024b). (IEA the exceed OECDGrid and globalfactors emission far exceed averages the (from in Indonesia OECD gCO 692.6 to 786.8 and global averages in Indonesia (from 692.6 to 786.8 gCO2/kWh), the Philippines (from 492.7 2/kWh), the Philippines (from 492.7 to 695 gCO2/kWh), and Vietnam (from 404.1 to 508.1 gCO2/kWh).to 695 gCO 2/kWh), and Vietnam (from 404.1 to 508.1 gCO2/kWh). Figure 1.7 Grid Emission Factors in the Four Focus Countries, Select Comparators, and the World, 2001–22 2UN Comtrade Database: 2023 data for HS (Harmonized Commodity Description and Coding System) codes 2701 (coal; briquettes, ovoids, and similar solid fuels manufactured from coal) and 2702 (lignite, whether or not agglomerated, excluding jet). 2 UN Comtrade Database: 2023 data for HS (Harmonized Commodity Description and Coding System) codes 2701 (coal; briquettes, ovoids, and similar solid fuels manufactured from coal) and 2702 (lignite, whether or not agglomerated, excluding jet). Official Use Only Official Use Only 12 Figure 1.7 Grid Emission Factors in the Four Focus Countries, Select Comparators, and the World, 2001–22 1,000 900 800 700 600 gCO2/kWh 500 400 300 200 100 0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 World OECD OECD Europe China Indonesia Philippines Vietnam Source: International Energy Agency. Source: International Energy Agency. Note: gCO 2/kWh Note: = grams gCO2/kWh of of carbon = grams dioxide carbon dioxide per per kilowatt-hour; kilowa OECD tt-hour [gCO2/kWh = Organisation OECD for = Organisation for Economic Economic Co-operation Co-operation and Development. and Development. The Energy 1.2 Energy 1.2 The ’sin Transition Transition’s Role Role in Improving Improving Regional Regional Energy Energy Security and Security and Relieving Dependence Relieving Dependence on Coal on Coal Rapid industrialization, digitalization, and transport electrification are pushing up electricity Rapid industrialization, demand. Between 2001 digitalization, and and 2024, the transport focus countries’electrification GDP grew 5–8 are pushing percent up electricity per year on average. demand. Between 2001 and 2024, the focus countries’ GDP grew 5–8 percent per year on The International Monetary Fund forecasts continued growth, at 4–6 percent, in 2025–2030 (IMF average. The International Monetary Fund 2025). forecasts The continued focus countries growth, are expectedat 4–6 percent,12,600 to achieve in 2025–2030 terawatt (IMF -hours2025). (TWh) The offocus countries are electricity expected to achieve 12,600 terawatt-hours (TWh) of electricity generation by 2030 generation by 2030 (figure 1.8) (World Bank 2023b), an increase of nearly 25 percent from 2023 (figure 1.8) (World Bank 2023b), an increase genera of nearly tion (10,200 25 percent TWh) (IRENA from 2025; 2023 MEMRgeneration (10,200 2024; NLDC TWh) (IRENA 2021–22; 2025; MEMR EVN 2023; 2024; NLDC Philippines 2021–22; EVN 2023; Department of Philippines Department Energy 2024a). Meanwhile, more 2024a). of Energy Meanwhile, than twice that—23,000 more than TWh oftwice that—23,000 combined combined TWh ofgenera tion—isgeneration—is expected to be expected needed to bybe needed 2060 by 2060 to meet to all nati meet onal, all national, long-term long-term economic growth economic growthtargets. targets. Under Under a business-as-usual scenario, a business-as-usual national scenario, GHG GHG national emissions are expected emissions to growto are expected from grow3 to from 3 to 25 percent due to this demand surge (fi gure 1.9; IMF 2022), underscoring the need to 25 percent due to this demand surge (figure 1.9; IMF 2022), underscoring the need to decouple the increase indecouple the increase electricity in electricity generation from agenera tion from a corresponding corresponding increase in GHG increase in GHG emissions emissions. Figure 1.8 Recent and Forecasted Power Sector Generation in the Four Countries, 2015–60 Figure Figure 1.8 Recent and Forecasted Power 1.8 Sector Generation in the Four Countries, 2015–60 Forecasted Power Generation 20,000 2,000 18,000 1,800 16,000 1,600 14,000 China +102% 1,400 Indonesia +455% 12,000 1,200 TWh TWh 10,000 1,000 8,000 800 Vietnam +438% 6,000 600 4,000 400 2,000 200 Philippines +285% 0 0 2015 2016 2017 2018 2019 2020 2021 2022 2023 2030 2035 2040 2045 2050 2055 2060 2015 2016 2017 2018 2019 2020 2021 2022 2023 2030 2035 2040 2045 2050 2055 2060 Source: World Bank; Indonesia’s National Electricity Plan (RUKN); Vietnam’s Revised Power Development Plan 8 (RPDP8); Official Use Only and the Philippine Energy Plan (PEP). Energy at a Crossroads 13 Figure 1.9 GHG Emission Projections in the BAU Scenario, 2015–60 n ndonesia +455% Vietnam +438% Philippines +285% 2019 2020 2021 2022 2023 2030 2035 2040 2045 2050 2055 2060 Source: Emissions Database for Global Atmospheric Research (EDGAR) and International Monetary Fund. Note: BAU = business as usual; GHG = greenhouse gas. Geopolitical tensions have left net coal importers, such as the Philippines and Vietnam, increasingly vulnerable to global price shocks and supply disruptions. Global trade disruptions and the war in Ukraine pushed coal prices to unprecedented levels, exceeding US$400/ton in 2022 (IEA 2023a), nearly four times that of 2020. Australian coal prices surged from US$86.83 in January 2021 to US$430.81 on September 2021 (World Bank 2024a). This coal price volatility translated into increased generation costs in both Vietnam and the Philippines, leading Vietnam’s national utility to register losses in both 2022 and 2023 (IEEFA 2024a). The cost of coal generation also doubled in the Philippines in 2022, raising the Manila Electric Company’s (Meralco’s) tariffs from P8.75 to P11.60 (US$0.15 to US$0.20) per kilowatt-hour. Indonesia benefited, however: the share US$0.20) per kilowatt-hour. Indonesia benefited, however: the share of GDP linked to coal mining of GDP linked to coal mining activities doubled from 3 percent in 2021 to 6 percent in 2022 (Rp 603 trillion activities doubled from 3 percent in 2021 to 6 percent in 2022 (Rp 603 trillion [US$40.2 billion] to Rp [US$40.2 billion] to Rp 1,296 trillion [US$86.4 billion]) (Agora Energiewende, ICSC, and IESR 2023). While prices 1,296 trillion [US$86.4 billion]) (Agora Energiewende, ICSC, and IESR 2023). While prices are expected are expected to decline around 12 percent in both 2025 and 2026 (World Bank 2024a), expanding domestic to decline around renewables percentrisks 12 volatility can reduce in both 2025 for net and 2026 (World Bank 2024a), expanding domestic importers. renewables can reduce volatility risks for net importers. Figure 1.10 Monthly Coal Prices in Australia, January 2021–November 2024 (US$/metric ton) Figure 1.10 Monthly Coal Prices in Australia, January 2021–November 2024 (US$/metric ton) 500 450 400 350 US$/metric ton 300 250 200 150 100 50 0 Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov Jan Mar May Jul Sep Nov 21 21 21 21 21 21 22 22 22 22 22 22 23 23 23 23 23 23 24 24 24 24 24 24 WorldBank. Source:World Source: Bank. The region is susceptible to climate-related hazards, requiring both climate mitigation and adaptation measures to shield the power sector from disruptions. The Notre Dame Global Adaptation Initiative Country Index (ND-GAIN) ranks Indonesia 97 out of 187, Vietnam 92, and the Official Use Only Philippines 115—indicating that they are particularly vulnerable to climate change impacts (figure 1.11; University of Notre Dame 2025). Increasingly frequent extreme weather events, including heat waves, droughts, floods, and typhoons, are destabilizing power systems and eroding economic stability in the region. The 2023 droughts in northern Vietnam shut down 11 hydropower stations, causing prolonged 14 The region is susceptible to climate-related hazards, requiring both climate mitigation and adaptation measures to shield the power sector from disruptions. The Notre Dame Global Adaptation Initiative Country Index (ND-GAIN) ranks Indonesia 97 out of 187, Vietnam 92, and the Philippines 115—indicating that they are particularly vulnerable to climate change impacts (figure 1.11; University of Notre Dame 2025). Increasingly frequent extreme weather events, including heat waves, droughts, floods, and typhoons, are destabilizing power systems and eroding economic stability in the region. The 2023 droughts in northern Vietnam shut down 11 hydropower stations, causing prolonged blackouts (Asia Pacific Foundation of Canada 2023). Typhoon Rai in the Philippines destroyed power sector infrastructure, causing over 3 million people to experience outages. Prolonged droughts in 2022 triggered widespread blackouts and factory shutdowns in China’s Sichuan Province, where 80 percent of electricity is hydropower based. The 2023 El Niño phenomenon prompted a 10.8 percent decline in hydropower in Indonesia over 2022–23, affecting South Sulawesi in particular (a 71 percent decline between August 2023 and October 2023), and forcing Indonesia’s state electric utility company (Perusahaan Listrik Negara, PLN) to implement rolling blackouts (PLN 2025). While resilience upgrades increase costs, additional renewables capacity can reduce long-term adaptation needs. Figure 1.11 Four Focus Countries’ Ranking on the Notre Dame Global Adaptation Initiative Country Index, 2023 Climate Change Vulnerability Index (2023) 0.6 #33 China 0.5 #92 Vietnam 0.4 #97 Indonesia Readiness #115 Philippines 0.3 0.2 0.1 0 0 0.1 0.2 0.3 0.4 0.5 0.6 Vulnerability Source: University of Notre Dame. Note: The ND-GAIN Country Index shows a country’s vulnerability to climate change and its readiness to leverage private and public sector investment for adaptive actions. ND-GAIN measures vulnerability across six sectors: food, water, health, ecosystem service, human habitat, and infrastructure. Readiness is assessed across three components: economic readiness, governance readiness and social readiness. The declining costs of variable renewable energy (VRE) technologies are rendering them increasingly competitive with traditionally dominant fossil fuels in the EAP. According to Wood Mackenzie, the levelized cost of energy (LCOE) for solar photovoltaic (PV) and onshore wind has declined across the focus countries (figure 1.12). In China, PV LCOE fell 90 percent—from US$379.37/MWh (2010) to US$38.05/MWh (2023); and the trend has been similar across Indonesia, Vietnam and the Philippines (Wood Mackenzie 2024). Onshore wind LCOEs also fell. PV and wind LCOEs are now below coal in China (US$63.06/MWh in 2023) and Vietnam (US$89.09/MWh in 2023). BloombergNEF forecasts further cost declines of 2–11 percent for solar, wind, and battery storage in 2025 and, despite trade barriers, a 22–49 percent drop in the LCOE for clean generation technologies by 2035 (BNEF 2025). Falling VRE capital costs hold the key to unlocking green hydrogen at scale, offering opportunities to decarbonize hard-to-abate sectors such as steel, cement, chemicals (e.g., ammonia and methanol), and transport. Energy at a Crossroads 15 Figure 1.12 Solar and Onshore Wind LCOE, 2010–50 LCOE $/MWh Forecast 500 450 LCOE Decrease (2010-2050) 400 350 China -95% -86% 300 Indonesia -92% -74% $/MWh 250 Philippines -92% -80% 200 Vietnam -95% -77% 150 100 50 0 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050 China - PV Indonesia - PV Philippines - PV Vietnam - PV China - Onshore Indonesia - Onshore Philippines - Onshore Vietnam - Onshore Source: Wood Mackenzie. Note: LCOE = levelized cost of electricity; MWh = megawatt-hour; PV = photovoltaic. Box 1.1 US Tariffs Offer an Opportunity to Spur the Regional Energy Transition The American Alliance for Solar Manufacturing Trade Committee’s filing of antidumping and countervailing duty cases with the US Department of Commerce and the US International Trade Commission in April 2024 resulted in the United States’ decision to impose duties ranging as high as 3,521 percent on solar imports from four Southeast Asian nations—Cambodia, Vietnam, Malaysia, and Thailand (which collectively accounted for US$12.9 billion in solar equipment exports to the United States in 2023) (Bloomberg 2025). As of January 2025, solar cell and module imports, by value, from Vietnam had declined by 91.5 percent, from Thailand by 90 percent, from Malaysia by 87 percent, and from Cambodia by 99.66 percent relative to January 2024 (American Alliance for Solar Manufacturing Trade Committee 2025). The global solar photovoltaic (PV) value chain (across polysilicon, wafers, cells, and modules) is highly concentrated. Owing to sustained government prioritization, China dominates all segments and, as of 2023, accounted for about 90 percent of the PV value chain (IEA-PVPS 2024). Other East Asia and Pacific (EAP) countries also serve as PV module production hubs—Vietnam (3.4 percent), Thailand (2.3 percent), and Malaysia (2.1 percent)—although Chinese companies have developed the majority of these countries’ manufacturing capacity, with a focus on exports to the United States (IEA 2022). While the wind energy manufacturing value chain is more diversified, the market is also dominated by China. China is responsible for manufacturing 80 percent of gearboxes, 80 percent of wind power converters, 70 percent of wind power generators, and 80 percent of castings (GWEC and BCG 2023). However, China’s share of finished wind turbine generators (WTG) is lower; 60 percent of 2022 global wind installations were produced and assembled in China (56 GW). About 88 percent of these were fabricated by Chinese original equipment manufacturers (OEMs) for the domestic market and less than 3 percent for export. Western OEM manufacturing in China predominantly serves export markets—roughly 9 percent, with less than 0.2 percent for domestic sales. With the installed capacity of solar and wind energy still low in EAP countries like Malaysia, Indonesia and Thailand, domestic and regional markets are well positioned to absorb the declining export demand. Increased trade volumes in the region would not only help achieve climate goals but also protect investments and jobs—and safeguard EAP economies from tariff impacts and uncertainties. Official Use Only 16 Carbon markets offer an additional avenue for making projects more viable and supporting the global energy transition. As of 2023, the European Union’s Emission Trading Scheme (EU ETS) helped European power and industrial plants reduce emissions by an estimated 47 percent relative to 2005 levels (European Commission 2023). From 2020 to 2023, EU ETS auction revenues allocated to member states tripled to €33 billion (EEA 2023). About 75 percent of this revenue was used for energy and climate change purposes between 2013 and 2022, with member states now obliged to spend 100 percent of revenues on related projects. The ecosystem of carbon pricing instruments in the focus countries remains limited, except in China (2021) and Indonesia (2023), which have implemented an ETS. Vietnam is developing a national ETS, with the expected launch of a pilot phase targeting the power and certain high-emission sectors in 2025 and fully operational ETS targeted by 2029, covering additional industrial sectors. The Philippines is exploring domestic carbon pricing instruments with the World Bank’s support (Philippines Department of Finance 2024). Voluntary carbon markets (VCMs) can provide additional capital for VRE project developers while helping industrial players offset otherwise hard-to-abate emissions. As private sector corporations increasingly commit to net zero ambitions and compliance-based markets begin to take shape in the region, VCMs will also be instrumental in fulfilling climate ambitions. McKinsey estimates that annual global demand for carbon credits could reach up to 1.5–2 GtCO2 by 2030 and around 7–13 GtCO2 by 2050, with market size exceeding US$50 billion by 2030 under a high price scenario (McKinsey 2021). The finalization of rules governing Articles 6.2 (Nationally Determined Contribution, via Internationally Transferred Mitigation Outcomes) and Article 6.4 (Paris Agreement Crediting Mechanism) of the Paris Agreement also expands EAP countries’ access to international capital for decarbonization investments. Corporate sustainability commitments are helping green energy sourcing gain traction in the form of clean energy procurement mandates. According to BloombergNEF, the corporate power purchase agreement (PPA) market grew 33 percent on average between 2015 and 2023, with nearly 9.7 gigawatts (GW) of VRE capacity contracted in Asia-Pacific in 2023 alone (BNEF 2024a). EAP is already a major contributor: of the 440 RE100 (“renewable energy 100 percent”) signatory businesses, more than 250 operate across EAP (Climate Group RE100 2024). Of these, the combined demand by RE100 members in the focus countries amounts to 50 TWh, signaling market appetite for clean energy procurement. Among the RE100 members in the focus countries, entities in China meet 50 percent of their electricity needs with renewable energy, followed by Indonesia at 35 percent, the Philippines at 31 percent, and Vietnam at 30 percent. Clean power trade among members of the Association of Southeast Asian Nations (ASEAN) could save about US$800 billion by 2050, or roughly 11 percent of combined net present costs, relative to independent domestic decarbonization routes (DNV 2023). Leveraging strong renewable resource endowments, regional cooperation in power trade can accelerate domestic VRE deployment at lower cost, increase reliability, minimize disruptions, and strengthen competitiveness. Both the Greater Mekong Subregion and ASEAN power grids are well positioned to stimulate regional power markets, meet growing domestic power demands, and enable collaborative power sector planning and electricity trading. Regional power trade will particularly be crucial for EAP countries like Singapore, which lack domestic VRE resources, while enabling power exporters like Indonesia and Lao People’s Democratic Republic (PDR) to earn revenue. As of January 2025, Singapore has granted conditional approval for 10 projects to import low-carbon power from Indonesia, Vietnam, Cambodia, and Australia (EMA 2025). Shifting to renewable energy can alleviate decreased labor productivity, reduce health-related costs, and cut mortality rates tied to air pollution. In Indonesia, air pollution is estimated to reduce life expectancy by 1.2 years on average—with associated labor income loss of 0.6 percent of 2019 GDP equivalent (World Bank 2023a). The World Health Organization estimated in 2016 that air pollution was linked to more than Energy at a Crossroads 17 60,000 deaths per year in Vietnam. Climate change diminished labor productivity among 51 percent of the respondents of a survey on climate change impacts and disasters in Vietnam, covering more than 10,000 local and foreign-owned businesses in the country (World Bank 2022a). The energy transition can help the region balance energy security, affordability, and sustainability. Power systems in the region are fragile and exposed to climate hazards and commodity supply fluctuations. Harnessing domestic renewable energy potential can help shield the region from commodity price shocks and infrastructure disruptions. A green electricity system helps retain foreign direct investment and meet private sector demand for renewable energy. 1.3 Key Objectives of this Report This report assesses the current state of renewable energy development in the EAP region, focusing on China, Indonesia, Vietnam, and the Philippines (the “focus countries”). These countries were selected based on their large and growing energy demand, projected economic growth, historical reliance on coal power generation, power sector emissions, and a renewable energy resource potential that can balance these other variables. The report aims to: 1. Assess the role of the EAP region and more specifically the focus countries in the clean energy transition, that is, the region’s contribution to global emissions and coal consumption and its implications for the energy transition. 2. Assess the renewable energy potential and current state of development, that is, current power sector and renewable energy trends in the focus countries, including renewable energy potential, historical drivers of growth, key achievements, and the scale of additional deployment required. 3. Identify VRE deployment barriers and develop strategic policy recommendations to accelerate the scale-up of clean energy, that is, analyze VRE adoption barriers (e.g., policy and regulatory gaps), financial constraints, grid infrastructure limitations, and the broader investment climate, drawing on stakeholder consultations to identify country-specific barriers and opportunities. This analysis follows a structured analytical framework to assess key barriers and enablers for scaling VRE investments. Lastly, recommendations are presented to address the key identified challenges, supported by global best practices in VRE deployment. 1.4 Research Approach and Methodology Several studies by the World Bank, International Energy Agency, International Renewable Energy Agency, United Nations Office for Project Services, Institute for Essential Services Reform, and other entities have evaluated renewable energy deployment and generation potential and the barriers to renewable energy scale-up and integration in the focus countries. This study does not undertake any additional power system modeling but synthesizes different studies’ outputs and findings. Private sector consultations clarifying the practical challenges to VRE in each market—from a project developer, financier, and investor perspective—contributed to the literature review. Finally, high-level recommendations based on a review of successful international case studies are presented, addressing the main challenges to further VRE deployment. Official Use Only 18 The analysis utilizes a market maturity model and structured analytical framework combining outputs from comprehensive desk research and stakeholder consultations, to provide a robust analysis of the renewable energy market status in the focus countries. The original analytical framework developed for this report leverages and builds on the World Bank Sustainable Renewables Risk Mitigation Initiative (SRMI), established in 2018. The SRMI Initiative is a partnership of the World Bank’s Energy Sector Management Assistance Program (ESMAP), the Agence Française de Développement (AFD), the International Renewable Energy Agency (IRENA), the International Solar Alliance (ISA), and Sustainable Energy for All (SE4all). In 2023, the Asian Development Bank (ADB), the European Bank for Reconstruction and Development (EBRD), the African Development Bank (AfDB), and the Deutsche Gesellschaft für Internationale Zusammenarbeit (GIZ) via the GET.transform program joined the Partnership. Key Methodology Steps The report’s preparation involved the following steps. 1. Secondary research and data collection: A comprehensive desk review of existing literature was conducted to establish the baseline of the renewable energy landscape in the EAP region and the four focus countries. The review encompassed: a. Official public datasets and national and regional policy documents, including national energy statistics, national power development plans, sectoral development plans, and regional energy policy documents. b. International and multilateral development organizations’ documents focused on renewable energy development. c. Think tank and analyst reports, and academic studies. 2. Primary research—private sector consultation: Building on the insights gained from the desk review, a series of targeted individual consultations were conducted with key stakeholders to gather in-depth insights into the dynamics of VRE in each of the focus countries, to gain a more nuanced understanding of market barriers. The consultations provided direct feedback on the challenges faced in developing and implementing VRE projects, and suggestions on initiatives and solutions that could ease and expedite the deployment of renewable energy. Insights were obtained on key areas of policy and permitting, land acquisition, grid infrastructure, offtake and project financing. To ensure a representative sample, participants were shortlisted from a diverse group of stakeholders, including VRE developers, financiers, industry associations, think tanks and others actively engaged in the VRE sector in the focus countries. 3. Data analysis and reporting: Findings from both primary and secondary research were analyzed and synthesized into this report. 4. Policy recommendations: Building on the insights gathered through the preceding analysis, consolidated policy recommendations for scaling up VRE were developed for each of the focus countries. Energy at a Crossroads 19 1.5 Analytical Framework The analytical framework underpinning this report considers sectorwide challenges and opportunities at three levels—sectoral objectives, sectorwide enabling pillars, and private sector implementation—ensuring a comprehensive evaluation from both public and private sector perspectives. Figure 1.13 A Graphic Outline of the Report’s Analytical Framework Energy Security Sectoral Energy Affordability Energy Energy Trilemma Sustainability Objec ves Pillar 1: Na onal Ambi on Pillar 2: Enabling Policies, Pillar 3: Infrastructure and Pillar 4: Financing and and RE Targets Regulatory Frameworks, and System Opera ons Investment Climate Suppor ng Ini a ves Public sector Net-Zero Targets Procurement & Tariff Grid Infrastructure Readiness Availability of Finance Framework Sector -wide Enabling Permi g & Land Acquisi on Financial Products Coverage & Pillars RE Ambi on & Growth Rate System Flexibility Efficiency Risk Mi ga on Climate Policy Alignment Market Reforms Dispatch Rules PPA Bankability Strategic Ac ons Private Procurement Process Land and Permi ng Transmission O ake Financing Private Sector sector Implementation Level Note: PPA = power purchase agreement; RE = renewable energy. Balancing energy security, affordability, and sustainability is fundamental to shaping the development of the power sector. Policy makers must navigate the complexities of these often-competing objectives to meet increasing energy demand. Policies must address diversification of energy sources in line with climate targets and decarbonization ambitions. Reducing dependence on fossil fuels, especially imported fuels, is critical to ensuring a resilient power sector built upon the fundamentals of energy security. At the same time, the power sector must provide access to competitively priced energy without sacrificing affordability for consumers. Regional power trade can facilitate access to lower-cost renewable energy resources while increasing grid reliability through shared resources. The result will be a more resilient and diversified energy supply, although institutional, regulatory, and technical barriers will have to be overcome to facilitate cross-border integration. Addressing the energy trilemma requires public sector planning that coordinates and considers national ambition, overarching policies, enabling regulations and institutional frameworks, strong infrastructure, and a supportive investment climate. The analytical framework of this report is tailored to the EAP region and focus countries, clustering the challenges to and enablers of renewable energy development and integration into four interconnected pillars: Official Use Only 20 Pillar 1: National ambitions and renewable energy targets. Clear climate commitments, including net zero and renewable energy targets, are essential to guide policy direction and investment. A cohesive ambition, developed through sectoral and ministerial collaboration, sets a clear and transparent road map and forms the basis for the policy mandates needed to attract investments in renewable energy. National ambitions should be supported by specific renewable energy targets that align with broader economic and climate strategies. Pillar 2: Enabling policies, regulatory frameworks, and supporting initiatives. Effective renewable energy deployment hinges on policies that foster investor confidence and long-term market stability. This pillar assesses renewable energy procurement policies and tariff frameworks (e.g., feed-in tariffs [FiTs], competitive auctions) as well as power market and utility reforms. Streamlining permitting and land acquisition processes is important to speed up renewable energy project development. Pillar 3: Infrastructure and system operations. Only a well-functioning power system can ensure energy security and system stability by accommodating geographically dispersed VRE resources. Power system planning must evolve to prioritize renewable energy, incorporate energy storage solutions, and enable flexibility for VRE. Market structures should facilitate competition by ensuring nondiscriminatory access to the grid, and cost-reflective pricing, while market rules should prioritize the dispatch of renewable energy over conventional fossil generation sources. Pillar 4: Financing and investment climate. Scaling investments requires a financial ecosystem that effectively mobilizes both public and private capital while mitigating risks. Public financing plays a crucial role in de- risking projects in their early stages, and catalyzing private sector participation. However, sustained capital flows depend on a predictable regulatory environment, the availability of bankable PPAs, and well-structured financial instruments. This pillar also highlights carbon markets and concessional financing as critical tools in improving the financial viability of renewable energy projects. Access to international carbon credit markets can create additional revenue streams, while concessional financing—through development finance institutions, green funds, or blended finance mechanisms—can lower the cost of capital and reduce project risks. Moreover, innovative risk-sharing instruments, such as credit guarantees and partial risk guarantees, can help bridge financing gaps and attract private investment into emerging renewable energy markets. A predictable and stable investment environment is key to unlocking private sector participation in renewable energy. Investors not only require strong policy signals, but also clear and transparent tariff and procurement frameworks, streamlined permitting and land acquisition processes, grid integration into the transmission infrastructure, bankable PPA structures, and innovative financing solutions to mitigate risks. These variables influence investment decisions surrounding project implementation and remain critical throughout execution and operation. Effectively managing these variables ensures renewable energy development is successful and sustainable in the long term. 1.6 Market Tiers—VRE Market Maturity VRE deployment across the EAP region is uneven and heterogenous, influenced by country-specific economic structures, climate ambitions, the policy and regulatory environment, as well as availability of domestic capital (breadth and depth of financial system). A one-size-fits-all approach cannot fully capture the region’s nuances and complexities. To tailor the analysis and policy recommendations, this report classifies countries into three market tiers—nascent, transitioning, and advanced—based on the level of VRE market maturity. Energy at a Crossroads 21 The tiering is informed by a combination of quantitative and qualitative considerations: • Quantitative indicators include the rate of penetration and integration of VRE technologies in capacity and generation mixes and VRE deployment growth trajectories, which signal the market’s momentum. • Qualitative indicators are aligned with the four-pillar analytical framework described above and assess the enabling environment for VRE. The indicators include, for example, national VRE ambition and target setting, effectiveness and stability of policy and regulatory frameworks, infrastructure and grid readiness for VRE integration, and strength of the investment climate, including financing tools and market risks. It is important to note that while the VRE penetration rate is an important quantitative indicator, market tiering considers the relative share of VRE and the broader enabling environment for sustained VRE scale-up. As such, some countries may exhibit relatively higher VRE penetration rates but are classified in lower market tiers due to limited system size, nascent regulatory environments, or challenges attracting large-scale investment. Conversely, countries with lower penetration rates but stronger institutional frameworks and ongoing market development activities may be classified in higher tiers. This approach ensures that the tiering reflects not only current deployment but also future growth potential and systematic readiness for renewable energy integration. Figure 1.14 Market Tiers and Their Characteristics Installed VRE share - VRE share - VRE (GW) capacity generation Advanced Market 1051.9 36.0% 15.55% High renewable energy penetration supported by strong policy foundations; 46.2 43.14% 23.50% facing integration challenges necessitating grid flexibility, accelerating ancillary services markets, and expanding energy storage solutions Installed VRE share - VRE share - VRE (GW) capacity generation Transitioning Market 22.3 26.61% 13.22% Growing momentum of renewable energy adoption with regulatory and Level of 2.1 7.42% 3.22% structural challenges hindering sustained growth, necessitating a Market Maturity 2.1 5.25% 0.27% stronger policy and regulatory framework 4.8 8.16% 4.20% Note: Scope of Country Coverage This report focus on a selected group of countries in the EAP region - China, Indonesia, Vietnam, the Philippines, Mongolia, Lao PDR, Australia, Cambodia, Malaysia, and Thailand. Other EAP countries - including Pacific Island nations, Brunei, Hong Kong, Installed VRE share - VRE share - Japan, Korea, Myanmar, New Zealand, Singapore, Timor-Leste, and others - are Nascent Market VRE (GW) capacity generation not covered in depth due to one or more of the following: Early stages of renewable energy adoption with 0.49 12.56% 7.35% • Smaller or fragmented power systems with limited large-scale renewables limited deployment of solar and wind deployment potential • Highly advanced market where renewable energy challenges are of a technologies, facing barriers such as unclear tariff 0.06 0.50% 0.13% frameworks and underdeveloped enabling different nature (e.g., Japan, Korea, Singapore, New Zealand) environments 0.26 16.75% 4.49% • Insufficient publicly available data to enable analysis • Distinct structural characteristics that require standalone analyses beyond Source: China (China Electricity Council), Indonesia the scope of this study 0.750 0.82% 0.34% (MEMR), Vietnam (EVN, NLDC & IRENA), Philippines (DOE) Other Countries - IRENA Stats Tool Note: Capacity Data for all countries is from 2023; Generation Data is for 2023 except for Australia, Malaysia, Thailand, Mongolia, Laos and Cambodia (2022) Note: DOE = Department of Energy; EAP = East Asia and Pacific; EVN = Electricity Vietnam; GW = gigawatt; IRENA = International Renewable Energy Agency; Lao PDR = Lao People’s Democratic Republic; MEMR = Ministry of Energy and Mineral Resources; NLDC = National Local Dispatch Centre; VRE = variable renewable energy. Official Use Only 22 Nascent markets remain in the early stages of VRE adoption. They have limited VRE capacity, weak policy frameworks, and unclear tariff frameworks and investment risk. Cambodia, Indonesia, Lao PDR, and Mongolia exemplify this category. While Lao PDR has a high penetration of renewables on account of high hydroelectric power, solar and wind energy capacity developments lag significantly. Even where VRE penetration is moderate relative to system size, major challenges persist, particularly the absence of clear, competitive, and transparent tariff frameworks. Robust policy and regulatory frameworks are therefore essential to create a level playing field and unlock VRE growth in these markets. Transitioning markets see increasing impetus for VRE adoption but regulatory and structural hurdles hinder sustained scale-up. Vietnam, the Philippines, and Malaysia fall in this category. While VRE penetration levels differ in these markets, policy activity, institutional reforms, and emerging market-driven mechanisms are significant. The Philippines is using auctions, renewable portfolio standards, and enhanced permitting frameworks, among other mechanisms, to strengthen its enabling environment. While these reforms are relatively recent and have yet to translate into large increases in VRE stock, the country is now well positioned for a substantial scale-up. Vietnam’s VRE penetration has exceeded the global average, thanks to generous FiT schemes and policy incentives in the early 2020s. However, recent years have seen investment flows disrupted and VRE projects stalled due to inconsistent policy implementation, underscoring the need for regulatory stability for sustained growth. For these markets, there is a critical need for clear and consistent procurement policies and pricing mechanisms, as well as streamlined permitting process, vital for investor confidence and a stable environment for renewables. Advanced markets have high VRE penetration and strong policy foundations, but renewables integration still faces obstacles. China, along with Australia, has installed substantial VRE capacity and penetration rates approaching or exceeding global benchmarks. China also dominates global VRE capacity additions—with over 1,400 GW installed wind and solar capacity—yet integration remains a challenge due to inflexible coal- dominated grids and curtailment risks. Success hinges on increasing grid flexibility, accelerating ancillary services markets, and expanding energy storage solutions.   Renewable Energy Integration in East Asia and Pacific 23 2. Renewable Energy Integration in East Asia and Pacific 2.1 The Four Focus Countries Hold Vast Renewable Energy Potential The East Asia and Pacific (EAP) region possesses significant renewable energy potential—with countries holding nearly 65,000 gigawatts (GW) of clean energy capacity, owing to their diverse geography and abundant natural resources (figure 2.1). China leads in renewable energy potential, due to its size and domestic reserves—solar (45,604 GW), wind (11,946 GW), hydro (660 GW), and bioenergy (594 GW),3 while Indonesia has the largest geothermal energy potential (23.7 GW), due to its location on the Pacific Ring of Fire. Vietnam has rich wind potential of 600 GW, thanks to its extensive coastline of 3,260 kilometers, favorable wind speeds, and shallow water depths (World Bank 2021). The Philippines has considerable offshore wind potential, of 178 GW, although over 90 percent lies at depths exceeding 50 meters, requiring the use of floating wind turbines (World Bank 2022b). High solar irradiation in the region yields large solar energy potential across all focus countries. Figure 2.1 Renewable Energy Potential in Focus Countries 58,534 GW 45,604 8,694 2,982 660 594 - 3,315 60.4 277 95 57 23.7 963 221 600 40 8.8 - 317 76 178 16.7 4.5 4.4 1,833 GW 597 GW 3,828 GW Sources: China – Wang et al. (2022); Indonesia – Ministry of Energy and Mineral Resources (Rencana Umum Ketenagalistrikan Nasional) and World Bank; Vietnam – PDP8; Philippines – Climate Analytics, World Bank and IRENA. Note: Data on the focus countries’ renewable energy resource potential has been shortlisted from a combination of sources, owing to the absence of a unified EAP resource potential assessment. Where available, national level resource assessments have been used. Offshore wind data for all countries have been sourced from World Bank studies. GW = gigawatts. 3 China biomass energy potential is estimated to be 460 million tons of coal equivalent (tce). This report uses a conversion factor of 1 tce = 8.141 megawatt-hours (MWh) to estimate the theoretical generation potential—3,745 terawatt-hours (TWh) and a 72 percent bioenergy capacity factor to estimate the corresponding generation capacity of 594 GW. Official Use Only 24 Across the focus countries, more than 97 percent of renewable potential remains undeveloped, with only 1,600 GW exploited as of 2023 (figure 2.2). Given its leading resource base, China has the largest underutilized capacity—nearly 57,000 GW across solar, wind, hydro, and bioenergy—while Indonesia is home to the largest untapped geothermal potential (21.1 GW). There is ample room to expand variable renewable energy (VRE), but growth in dispatchable renewables is more constrained. In hydropower, China and Vietnam have realized about 60 percent of their potential, with further expansion possible in Indonesia and the Philippines. The Philippines has tapped into nearly 45 percent of its geothermal capacity, while Indonesia still has significant scope to develop its geothermal resource. Figure 2.2 Untapped Renewable Energy Potential in the Focus Countries (% and GW) Untapped Renewable Energy Potential - Focus Countries (Percent & GW) 100 % 99.98% 99.96% 99.84% 99.32% 98.69% 98.66% 98.27% 90% 96.23% 95.45% 94.78% 94.04% 93.05% 80% 89.03% 86.67% 77.25% 70% 60% 50% 55.68% 40% 42.00% 30% 36.06% 20% 10% 0% Ch ina Indo nes ia Vietn am Ph ili pp ine s Solar 44,994 GW 3,314.4 GW 946.3 GW 315.4 GW Wind 11,234 GW 337.25 GW 815.4 GW 253.6 GW Hydro 238 GW 88.4 GW 16.8 GW 12.9 GW Bio 563 GW 53.6 GW 8.4 GW 3.9 GW Geo - 21.1 GW - 2.5 GW Sources: China – Wang et al. (2022); Indonesia – Ministry of Energy and Mineral Resources (Rencana Umum Ketenagalistrikan Nasional) and World Bank; Vietnam – PDP8; Philippines – Climate Analytics, World Bank and IRENA. Note: Data on the focus countries’ renewable energy resource potential has been shortlisted from a combination of sources, owing to the absence of a unified EAP resource potential assessment. Where available, national level resource assessments have been used. Offshore wind data for all countries have been sourced from World Bank studies. GW = gigawatts. Considering the resource potential and technology-specific capacity factors behind renewable energy generation, the focus countries have sufficient potential to drive the clean energy transition and coal phaseout. In each country, the combined dispatchable renewable energy and VRE generation potential surpasses the forecasted electricity generation projections (over 23,000 TWh by 2060; figure 2.3).4 Vietnam’s potential is nearly threefold higher than the 1,360–1,511 TWh electricity generation (including imports) forecasted for it in 2050 under the Revised Power Development Plan 8 (RPDP8). The Philippines could leverage its dispatchable renewable energy capacity and wind energy potential to fully meet all of its projected 454 TWh generation in 2050 under the Reference Scenario in the Philippine Energy Plan for 2023–50 (Philippines Department of Energy 2024c). Indonesia’s 4,646 TWh solar potential is over 13 times as much as its 2023 electricity generation. The country has dispatchable geothermal and hydro reserves, and could optimize its solar energy potential to meet the forecasted 1,947 TWh production in 2060 (MEMR 2025). The World Bank’s 4 Data for China from World Bank’s Net Zero Assessment; Indonesia from MEMR (2025); Vietnam from the revised PDP8; and Philippines the Department of Energy (2024b). Renewable Energy Integration in East Asia and Pacific 25 net zero assessment for China suggests 19,000 TWh generation by 2060, which the country could achieve by leveraging its vast VRE potential alongside hydro and bioenergy. While the EAP region has sufficient VRE and dispatchable renewable energy potential, long-term development of the power sectors hinges on the ability to balance renewable energy and residual fossil-capacity (with carbon capture, use, and storage). Figure 2.3 Renewable Energy Generation Potential and Projected Generation (TWh) Renewable Energy Generation Potential and Projected Generation (TWh) 1,000,000 10,000 TWh 100 1 Ch ina Indo nes ia Vietn am Ph ili pp ine s Solar 63,919 TWh 4,646 TWh 1,350 TWh 444 TWh Onshore 27,417 TWh 190 TWh 697 TWh 240 TWh Offshore 10,710 TWh 338 TWh 2,155 TWh 639 TWh Hydro 4,741 TWh 441 TWh 186 TWh 78 TWh Bio 3,745 TWh 360 TWh 56 TWh 28 TWh Geo - 170 TWh - 32 TWh Projected 19,140 TWh 1,947 TWh 1,360-1,511 TWh 454 TWh Generation (2060) (2060) (2050) (2050) Source: Original compilation. Note: Renewable energy generation potential is calculated by multiplying the renewable energy capacity potential with capacity factors from IRENA (2024a). Capacity factors used are geothermal (82 percent), hydro (53 percent), bio (72 percent), solar (16 percent), offshore wind (41 percent), and onshore wind (36 percent). TWh = terawatt-hour. 2.2 Renewable Energy’s Share of Generation Varies Across the Region The share of renewable energy in generation varies across EAP, with hydropower the largest contributor in most countries.5 In New Zealand, Lao PDR, and Cambodia, hydropower resources dominate the share of clean energy in the generation mix. VRE’s contribution remains varied, led by Australia, Vietnam, and China. While both China and Vietnam have substantial hydropower potential, a rapid deployment of VRE has enabled a large renewables share in generation. The Philippines currently lags its peers in VRE penetration; however, this is expected to change as large solar and wind capacities—now under procurement and construction—come online. In Indonesia, renewable energy deployment has been irregular; despite efforts to expand geothermal, hydro, and bioenergy, meaningful VRE remains absent. 5 National power sector statistics (for China, Indonesia, Vietnam, and the Philippines) included in this section cover the period 2015–23. Data from 2024 were not considered due to either partial availability or preliminary results. For other countries, data have been sourced from the IRENA Stats Tool with time frame coverage as follows: install capacity (2015–23) and generation (2015–22). Refer to appendix B for details on the energy transition in non-EAP countries. Official Use Only currently lags its peers in VRE penetration; however, this is expected to change as large solar and wind capacities— now under procurement and construction—come online. In Indonesia, renewable energy deployment has been irregular; despite efforts to expand geothermal, hydro, and bioenergy, meaningful VRE remains absent. Figure 2.4 Renewable Energy’s Share of the Electricity Generation Mix, 2022 26 86.57% 100% 76.62% 90% Figure 2.4 Renewable Energy’s Share of the Electricity Generation Mix, 2022 65.76% 63.09% 80% 70% 49.35% 48.48% 86.57% 60% 100 % 50% 90% 76.62% 30.93% 65.76% 30.21% VRE 63.09% 40% 80% 22.35% 22.14% 52.02% 19.60% 17.86% Hydro 48.48% 70% 30% 60% Geothermal 8.00% 30.93% VRE 30.21% 4.86% 20% 50% 3.01% 0.92% 0.03% 22.35% 22.26% Bio 19.60% 17.86% 10% 40% Other RE 30% 8.00% 0% Hydro 4.86% 3.01% 0.92% 20% 0.03% Geothermal m a re a s R ar a a n sia lia sia lia nd R ei 10% ne di in re re SA pa PD un na po nm ra go la ne ay Ch bo Ko Ko pi Ja st a et Br ng ga o on al do ya ilip Bio m Ze 0% La Au of Vi R M Ko Sin M Ca M DP In Ph w ic nd ia a ar ia es ia ia a ia e R i ng R a n Ne bl e m l a s s e l r e a PD d or na tra hi n n or go po SA un pu Ho al bo et nm ap pi ne ay o K s C J al K on ga ng Br Re Ze Vi ya ilip do of a, La Ca m R Au M Sin Ko DP in w M Ph In ic M Ch Ne bl ng pu Ho Re n a, Source: International Renewable Energy Agency, Indonesia’s Ministry of Energy and C Mineral Resources, Electricity Vietnam hi (EVN), Vietnam’s National Local Dispatch Centre, and Philippine’s Department of Energy. Source: International Renewable Energy Agency, Indonesia’s Ministry of Energy and Mineral Resources, Electricity Vietnam 23.49% Note: EAP (EVN), = East Asia Vietnam’s and Pacific; National VRE = variable Local Dispatch Centre, renewable energy. and Philippine’s Department of Energy. 25% Note: EAP = East Asia and Pacific; VRE = variable renewable energy. 20% 13.95% 13.46% 2.3 Deep Dive into the Focus Countries 10.00% 15% 2.3 Deep Dive into the Focus Countries 7.40% 7.03% 10% expansions in China have been driven by VRE projects over the past decade. From 2015 to Capacity 5.26% 4.46% Wind 2.63% 2023, solar Capacity and wind expansions incapacities China have surged been driven by almost by VRE 900 GW combined projects over the(IRENA past decade. 2025).From 2015 Solar energy to 2023, grew 1.31% 0.65% 0.57% 0.50% 0.27% 5% 0.14% 0.13% 0.03% Sol ar solar and wind capacities surged by almost 900 GW rapidly, from approximately 40 GW to just over 600 GW. Likewise, energy installations grew, withcombined (IRENA 2025). Solar energy grew rapidly, from approximately 0% capacity more GW to 40than just over tripling over600 the GW. Likewise, energy installations grew, with capacity more than tripling a ina apan dia d aperiod a tos reach e ar440 a GW. AR Wind sia and sia solar DR ne i installed capacity ali am an re oli ne or m re over the period str to tn reach Ch 440 J GW. mb o Wind a l fK o and on gsolar pi installed ga p n capacity K o ng Sexceeded al ay ne 1,400o P GWru combined by end- exceededAu1,400 Vie GW combined Ca ewby 2024 Ze l ico end. M P hilThe ip Sindevelopment M ya DPR g Ko of VRE M capacity Indo La at B scale has facilitated 2024. The development of VRE capacity N pu b at scale has facilitated a gradual on reduction of coal’s prominence in the a gradual reduction of coal’s prominence Re in the generation ina , Hmix. generation mix. Ch Figure 2.5 Installed Capacity and Generation Mix in China, 2015–22 Figure 2.5 Installed Capacity and Generation Mix in China, 2015–22 3,500 40% 10,000 16% 3,000 35% 9,000 14% Wind 8,000 30% 2,500 Solar 12% 7,000 25% Hydro 10% 6,000 VRE Share 2,000 VRE Share 20% Bio TWh GW 5,000 8% 1,500 Others 15% 4,000 6% Nuclear 1,000 3,000 10% Oil 4% 2,000 Gas 500 5% 1,000 2% Coal 0 0% 0 0% 2015 2016 2017 2018 2019 2020 2021 2022 2023 2015 2016 2017 2018 2019 2020 2021 2022 Source: International Renewable Energy Agency. Source: International Renewable Energy Agency. In Indonesia, dispatchable sources—hydro, geothermal, and bioenergy—have advanced renewable energy dispatchable In Indonesia, while development, solar andsources—hydro, geothermal, wind energy potential and bioenergy—have remains largely advanced untapped. Hydro capacity, renewable the dominant renewable energy source, increased nearly 25 percent from 2015 to 2023 (to 6.6 GW) (MEMR 2024), whereas combined solar and wind capacities were a mere 0.75 GW by end-2023. Fossil fuels continue to dominate both installed capacity (85 percent) and the generation mix (80 percent) (figure 2.6). 6 Official Use Only 6 Includes data for both on- and off-grid power plants. energy development, while solar and wind energy potential remains largely untapped. Hydro capacity, the dominant renewable energy source, increased nearly 25 percent from 2015 to 2023 (to energy development, while solar and wind energy potential remains largely untapped. Hydro 6.6 GW) (MEMR 2024), whereas combined solar and wind capacities were a mere 0.75 GW by end- capacity, the dominant renewable energy source, increased nearly 25 percent from 2015 to 2023 (to 2023. Fossil fuels continue to dominate both installed capacity (85 percent) and the generation mix 6.6 GW) (MEMR 2024), whereas combined solar and wind capacities were a mere 0.75 GW by end- (80 percent) (figure 2.6).6 2023. Fossil fuels continue to dominate both installed capacity Renewable Energy(85 percent) Integration and Asia in East the and Pacific mix generation 27 Figure (80 2.6 Installed percent) Capacity and Generation Mix in Indonesia (figure 2.6). 6 Figure 2.6 Installed Capacity Figure 2.6 and A. Capacity Installed Generation mixCapacity Mix in Indonesia B. Electricity and Generation Mix in Indonesia, generation mix 2015–23 400 0.40% 100 A. Capacity mix 0.90% B. Electricity generation mix 90 0.80% 350 0.35% Wind 80 400 0.40% 100 0.70% 0.90% 300 0.30% Solar 70 90 0.60% 350 0.35% 0.80% Wind 250 0.25% Hydro VRE Share 60 VRE Share 80 0.50% 0.70% 300 0.30% TWh 50 Solar 200 0.20% GW Geothermal 70 0.40% 0.60% 40 250 0.25% Hydro 150 0.15% VRE Share 60 Bio VRE Share 0.30% 0.50% TWh 30 50 200 0.20% GW Geothermal Oil 100 0.10% 20 0.20% 0.40% 40 Bio 150 0.15% 10 0.10% 0.30% Gas 50 0.05% 30 0 0.00% Oil Coal 100 0 0.10% 0.00% 20 0.20% 2015 2016 2017 2018 2019 2020 2021 2022 2023 Gas 50 0.05% 10 0.10% 15 16 17 18 19 20 21 22 23 20 20 20 20 20 20 20 20 20 0 0.00% Coal 0 0.00% 2015 2016 2017 2018 2019 2020 2021 2022 2023 15 16 17 18 19 20 21 22 23 Source: Indonesia’s Ministry of Energy and Mineral Resources. 20 20 20 20 20 20 20 20 20 Source: Indonesia’s Ministry of Energy and Mineral Resources. Vietnam’s Source: power Indonesia’s sector Ministry has shifted of Energy to VRE and Mineral as hydropower has largely been exploited. Although Resources. power continues hydropower Vietnam’s sector has to account shifted for as to VRE a significant hydropower has (28 share percent) largely of the capacity been exploited. Althoughmix, Vietnam’s hydropower Vietnam’s VRE sector power expandedsector has shifted to VRE as hydropower has largely been exploited. Although continues to account for asignificantly, from significant share virtually (28 percent)nonexistent to more of the capacity mix,than 20 GW Vietnam’s of sector VRE capacity (IRENA expanded hydropower 2025; NLDC continues 2021–22; to account for a significant share (28 percent) of the capacity mix, Vietnam’s significantly, from virtually EVN 2023) between nonexistent 201820 to more than andGW 2021, amid generous of capacity tariffNLDC (IRENA 2025; 2021–22;Solar mechanisms. EVN VRE sector projects 2023) between expanded have made 2018 significantly, andimpressive 2021, from amidstrides generous virtually and now tariff nonexistent account mechanisms. to more for nearly Solar projectsthan 20 percent 20 have GW of theof made capacity installed impressive (IRENA capacity strides and2025; (figureNLDC 2.7). 2021–22; now account At forthe same nearly EVN 2023) 20time, percent between coal-fired of 2018 power the installed and 2021, capacity capacity has amid grown (figure generous 2.7). rapidly, tariff to At the same mechanisms. about time, 28 2023, GW in power coal-fired Solar projects capacity hashave dominating grownmade impressive rapidly, electricity to about strides generation28 GW with and in now a2023, 46 account dominating percent for share nearly 20 electricity (130 TWh) (IRENAof percent generation theainstalled with 2025; 46 NLDCpercentcapacity share 2021–22; (figure (130 TWh) EVN 2.7). (IRENA 2025; NLDC 2021–22; EVN 2023). 2023). At the same time, coal-fired power capacity has grown rapidly, to about 28 GW in 2023, dominating electricity generation with a 46 percent share (130 TWh) (IRENA 2025; NLDC 2021–22; Figure 2.7 Installed FigureCapacity and Generation 2.7 Installed Capacity andMix in Vietnam Generation Mix in Vietnam, 2015–23 EVN 2023). Figure 2.7 Installed Capacity and A. Capacity mix Generation Mix in Vietnam B. Electricity generation mix 300 16% 90 30% A. Capacity mix B. Electricity generation mix 14% 80 Wind 250 25% 12% 70 Solar 300 16% 90 30% 200 60 20% Hydro 10% 14% 80 Wind 250 VRE Share VRE Share VRE Share VRE Share 50 25% TWh Bio 150 8% 12% 15% GW 70 Solar 40 200 60 20% Others 6% 10% 30 10% Hydro 100 50 4% TWh Oil 150 8% 20 15% Bio GW 40 5% 50 10 Gas 2% 6% Others 30 10% 100 0 0% Coal Oil 0 0% 4% 20 2015 2016 2017 2018 2019 2020 2021 2022 2023 5% 50 15 16 17 18 19 20 21 22 23 10 Gas 2% 20 20 20 20 20 20 20 20 20 0 0% Source: Electricity Vietnam (EVN), Vietnam’s National Local Dispatch Centre, and International Renewable Energy 0% 0 Coal Agency. Source:2015 2016 2017 2018 2019 2020 2023 2021 2022 National Note: VRE =Electricity Vietnam variable renewable (EVN), Vietnam’s energy. Local Dispatch Centre, and International Renewable Energy Agency. 15 16 17 18 19 20 21 22 23 20 20 20 20 20 20 20 20 20 Note: VRE = variable renewable energy. The Philippines’ Source: power Electricity Vietnamsector, (EVN),despite Vietnam’s being the National smallest, Local in Dispatch termsand Centre, both installed of International capacity Renewable andAgency. Energy power The VRE Note: Philippines’ = variable power sector, renewable energy. despite being the smallest, in terms of both installed capacity and generation, among the focus countries, is the most dependent on coal. From 2015 to 2023, coal capacity more than doubled, from 6 GW to 12.4 GW (Philippines Department of Energy 2024a). Fossil fuels, primarily The Philippines’ power sector, despiteof 6 Includes data for both on- and off-grid power plants. coal, continue to meet nearly 80 percent being the smallest, electricity demand. inVRE terms of both capacity installed remains capacity minimal, and with a combined solar and wind contribution of approximately 2 GW to the capacity mix and 3 percent to generation (VRE capacity is under procurement; more than 5.3 GW were auctioned across the first two rounds of the 6 Includes data for both on- and off-grid power plants. Green Energy Auction Program) (Philippines Department of Energy 2022, 2023). Official Use Only Official Use Only Official Use Only power generation, among the focus countries, is the most dependent on coal. From 2015 to 2023, coal capacity more than doubled, from 6 GW to 12.4 GW (Philippines Department of Energy 2024a). Fossil fuels, primarily coal, continue to meet nearly 80 percent of electricity demand. VRE capacity remains minimal, with a combined solar and wind contribution of approximately 2 GW to the capacity mix and 3 percent to generation (VRE capacity is under procurement; more than 5.3 GW were auctioned 28 across the first two rounds of the Green Energy Auction Program) (Philippines Department of Energy 2022, 2023). Figure 2.8 Installed Capacity and Generation Mix in the Philippines Figure 2.8 Installed Capacity and Generation Mix in the Philippine, 2015–23s A. Capacity mix B. Electricity generation mix 30 8% 120 4% 7% 3% 25 Wind 100 6% Solar 3% 20 80 5% Hydro VRE Share VRE Share 2% TWh 15 4% 60 GW Geothermal 2% 3% Bio 10 40 1% 2% Oil 5 20 1% 1% Gas 0 0% Coal 0 0% 2015 2016 2017 2018 2019 2020 2021 2022 2023 2015 2016 2017 2018 2019 2020 2021 2022 2023 Source: Philippines Department of Energy. Source: Philippines Department of Energy. Note: Note: VRE= VRE variable renewable =variable energy. renewable energy. 2.4 2.4 Look AA at the Look Rest at the of the ofRegion Rest the Region InInthe therest the ofof rest theEAP EAP region, VRE region, VREadditions have additions grown have the the grown fastest relative fastest to other relative generation to other sources, generation with solar with sources, capacity solarmore tripling than more capacity andtripling wind capacity than and windmore than doubling capacity more thanbetween 2015 doubling and 2023 between (IRENA 2015 2025). In contrast to the large shares of coal capacity in the focus countries, the rest of EAP and 2023 (IRENA 2025). In contrast to the large shares of coal capacity in the focus countries, the restrelies most notably onofnatural gas. most EAP relies From notably 2015 to on2023, the region’s natural overall gas. From 2015 installed to 2023, capacity grew 27 the region’s percent, overall with coal installed and gas capacity growing moderately, at 16.8 and 17.2 percent, respectively (figure 2.9). Of the region’s grew 27 percent, with coal and gas growing moderately, at 16.8 and 17.2 percent, respectively (figure nearly 130 GW solar capacity, the resource-rich and energy-intensive economies of Australia and Japan together accounted for the 2.9). Of the region’s nearly 130 GW solar capacity, the resource-rich and energy-intensive economies lion’s share—nearly 120 GW. of Australia and Japan together accounted for the lion’s share—nearly 120 GW. While While VRE’s VRE’s share share of of electricity electricity generation generation in the in the rest rest of remains of EAP EAP remains under under 10 percent, annualannual 10 percent, growth is swift. growthFromis 2015 to swift. 2022,2015 From the shares of solar to 2022, the and wind shares oftripled wind than solar and more doubled, tripled and morerespectively, as gas and than doubled, coal registered similar growth (gas at about 32.4 percent and coal at roughly 31.8 percent respectively as gas and coal registered similar growth (gas at about 32.4 percent and coal at roughlyin 2022). While coal and 31.8gas installed percent incapacity grew, both 2022). While andin coal fell absolute gas terms installed over 2015–22, capacity grew, bothwith coal fell in generation fallingover absolute terms roughly percent, from 72015–22, 871 to 809 TWh, and gas generation roughly 5.6 percent, from 874 to 825 with coal generation falling roughly 7 percent, from 871 to 809 TWh, and gas generation TWh. roughly 5.6 percent, from 874 to 825 TWh. Figure 2.9 Installed Capacity and Generation Mix in the Rest of EAP, 2015–22 Figure 2.9 Installed Capacity and Generation Mix in the Rest of EAP, 2015–22 A. Capacity mix B. Electricity generation mix 900 25% 3,000 9% Wind 800 8% Solar 2,500 700 20% 7% Hydro 600 2,000 6% 15% VRE Share Geothermal VRE Share 500 5% TWh 1,500 GW 400 Bio 4% 10% 300 Others 1,000 3% 200 Nuclear 2% 5% 500 100 Oil 1% 0 0% Gas 0 0% 201520162017201820192020202120222023 Coal 2015 2016 2017 2018 2019 2020 2021 2022 Official Use Only Source: International Renewable Energy Agency. Note: EAP Source: = East Asia International and Pacific; Renewable VRE =Agency. Energy variable renewable energy. Note: EAP = East Asia and Pacific; VRE = variable renewable energy. 2.5 Drivers of Regional VRE Growth Progress in VRE deployment across the region has been shaped by a combination of climate commitments, policy orientation, market-driven incentives, and supportive regulatory frameworks (figure 2.10). Although each country follows a distinct trajectory influenced by its resource endowments, economic structure, and regulatory environment, common themes shape investment and renewable energy capacity deployment trends. Renewable Energy Integration in East Asia and Pacific 29 2.5 Drivers of Regional VRE Growth Progress in VRE deployment across the region has been shaped by a combination of climate commitments, policy orientation, market-driven incentives, and supportive regulatory frameworks (figure 2.10). Although each country follows a distinct trajectory influenced by its resource endowments, economic structure, and regulatory environment, common themes shape investment and renewable energy capacity deployment trends. Figure 2.10 Analytical Framework—Pillars Supporting Renewable Energy Growth Energy Security Sectoral Energy Affordability Energy Energy Trilemma Sustainability Objec ves Pillar 1: Na onal Ambi on Pillar 2: Enabling Policies, Pillar 3: Infrastructure and Pillar 4: Financing and and RE Targets Regulatory Frameworks, and System Opera ons Investment Climate Suppor ng Ini a ves Public sector Net-Zero Targets Procurement & Tariff Grid Infrastructure Readiness Availability of Finance Framework Sector -wide Enabling Permi g & Land Acquisi on Financial Products Coverage & Pillars RE Ambi on & Growth Rate System Flexibility Efficiency Risk Mi ga on Climate Policy Alignment Market Reforms Dispatch Rules PPA Bankability Strategic Ac ons Private Procurement Process Land and Permi ng Transmission O ake Financing Private Sector sector Implementation Level Note: PPA = power purchase agreement; RE = renewable energy. Enabling Pillar I. National Ambition and Renewable Energy Target Many EAP governments, including those of the focus countries, are pushing ahead for power-sector decarbonization. Paris Agreement–aligned national ambitions to cut economywide greenhouse gas (GHG) emissions signal the power sector’s shift toward renewable energy. Long-term climate commitments provide policy predictability, strengthen investor confidence, and catalyze investment in low-carbon technologies, ensuring sustained demand for clean energy. All focus countries except the Philippines have announced countrywide net zero targets. All national governments with revised Nationally Determined Contributions include decarbonization in their long-term economic planning. Indonesia and Vietnam also participate in the Just Energy Transition Partnership. All national governments have adopted broader renewable energy and VRE targets. As rapid industrialization, digitalization, electric mobility, rising adaptation needs (e.g., cooling), and widespread electrification accelerate, these targets support power-sector expansion for the next phase of economic growth, catalyzing a more sustainable and resilient power system while reducing reliance on commodity imports. Official Use Only 30 Table 2.1 Summary of Renewable Energy Targets Country Policy/Plan Target • 50 percent increase in renewable energy 14th Five-Year Plan (2021–25) on generation from 2020 to 2025 China Renewable Energy Development • 1,200 gigawatts of variable renewable energy by 20307 National Energy Policy (KEN) of • 23 percent share of renewables in total energy 2014 supply by 20258 Indonesia Electricity Supply Business Plan • Renewables represent over 50 percent of the (Rencana Usaha Penyediaan Tenaga planned 40,575 megawatts (MW) of generation Listrik, RUPTL): 2021–30 of the capacity addition9 state electric utility company, PLN • Renewables contribute 15–20 percent of the National Energy Master Plan total primary energy supply by 2030, and 80–85 (NEMP) percent by 2050 Vietnam • Onshore/nearshore wind capacity of 38,029 MW Revised Power Development Plan 8 and solar capacity of 73,416 MW by 2030 (RPDP8) • Offshore wind capacity of 17,032 MW with targets pushed back between 2030 and 2035 National Renewable Energy • Renewable energy represents 35 percent of power Philippines Program (NREP) 2020–40 mix by 2030 and 50 percent by 2040 Enabling Pillar II. Enabling Policies, Regulatory Frameworks, and Supporting Initiatives Adequate policies supporting project implementation, procurement, and pricing mechanisms are essential to support VRE capacity additions. In the focus countries, tariff mechanisms such as feed-in tariffs (FiTs) (e.g., Vietnam) and competitive auctions (e.g., the Philippines) have mainly led VRE growth. While creating a conducive investment and innovation environment, these strategies ensure both economically viable and market-aligned VRE growth, besides signaling long-term commitment to VRE, essential for planning and financing large-scale projects. 7 Target achieved in 2024, six years ahead of schedule. 8 Revised to 17–19 percent by 2025 in the draft KEN 2024 (IESR 2024). 9 PLN’s updated RUPTL and Indonesia’s updated KEN policy are being drafted and are expected to promote a larger renewable energy contribution in the power sector leading to 2050 and 2060. The revised targets are expected to reflect the country’s ambition to build 75 GW of renewable energy over the next 15 years. Refer to appendix C for details on focus countries’ NDCs and power sector plans. Adequate policies supporting project implementation, procurement, and pricing mechanisms are essential to support VRE capacity additions. In the focus countries, tariff mechanisms such as feed-in tariffs (FiTs) (e.g., Vietnam) and competitive auctions (e.g., the Philippines) have mainly led VRE growth. While creating a conducive investment and innovation environment, these strategies ensure both economically viable and market-aligned VRE growth, besides signaling long-term commitment to VRE, essential for planning and financing large-scale projects. China Renewable Energy Integration in East Asia and Pacific 31 Early VRE capacity expansion was enabled by policies such as the “national subsidy” program, then shifting toward auctions—including grid parity tenders (20-year contracts with prices at or below local China coal tariffs). China’s upcoming move to a UK-style contracts-for-difference auction should lower prices Early VRE capacity expansion was enabled by policies such as the “national subsidy” program, then shifting further. toward Market-based tools—green auctions—including power grid parity tenderstrading andcontracts (20-year carbon markets—also with prices at ordrove VRE; below localin 2024, coal tariffs). green electricity trading reached 233.6 billion kilowa tt -hours (kWh) (China Daily 2025). China’s upcoming move to a UK-style contracts-for-difference auction should lower prices further. Trea ti ng solar Market- photovoltaic (PV) as a based tools—green strategic, power export-oriented trading industry—backed and carbon markets—also by manufacturing drove VRE; in 2024, greensubsidies electricityand trading large SOE-supported reached 233.6 billionbank loans (IGCC kilowatt-hours 2023)—paved (kWh) (China Dailythe way Treating 2025). for a domes solarti c, self-sufficient photovoltaic PVavalue (PV) as strategic, chain. export-oriented industry—backed by manufacturing subsidies and large SOE-supported bank loans (IGCC 2023)—paved the way for a domestic, self-sufficient PV value chain. Indonesia In Indonesia Indonesia, renewable energy project tariffs were traditionally set case by case, capped by the In Indonesia, renewable energy project tariffs were traditionally set case by case, capped by the national or national or local generation cost (Biaya Pokok Penyediaan Pembangkitan or BPP), but this—given the local generation cost (Biaya Pokok Penyediaan Pembangkitan or BPP), but this—given the low coal generation low coal generation costs—undermined renewable energy project attractiveness. Presidential costs—undermined renewable energy project attractiveness. Presidential Regulation (PR) 112/2022 ended Regulation (PR) 112/2022 ended BPP-based tariffs, subjecting them to annual ceiling prices, adjusted BPP-based tariffs, subjecting them to annual ceiling prices, adjusted for project location, technology, and project forsize. technology, location,also PR 112/2022 and size. PR enabled Indonesia’s 112/2022 state also enabled electric utility Indonesia’s (Perusahaan state electric Listrik Negara, PLN) tou tility use direct (Perusahaan Listrik Negara, PLN) to use direct selec ti on via compe selection via competitive bidding, in addition to direct appointment. titi ve bidding, in addi ti on to direct appointment. Figure 2.11 Ceiling Tariff Ranges Figure 2.11 Ceiling Tariff Ranges Ceiling Tariff Ranges based on Size, Weight, and Location Factor 30 Solar Wind Hydro Biomass Biogas Geothermal 17.33 16.83 25 17.21 16.85 14.64 15.27 13.86 12.45 20 USD Cents/kWh 10.32 10.1 10.53 15 9.17 10 5 7.43 7.65 6.68 6.5 5.56 5.94 5.95 4.72 3.34 4.01 3.57 2.95 0 Year Year Year Year Year Year Year Year Year Year Year Year 1-10 11-30 1-10 11-30 1-10 11-30 1-10 11-30 1-10 11-30 1-10 11-30 Source: Presidential Regulation 112/2020. Source: Presidential Regulation 112/2020. Vietnam Vietnam Vietnam’s generous FiT of 2017 made rapid solar PV expansion possible. Solar tariffs at Vietnamese dong (D) Vietnam’s generous 2,086/kWh FiT of 2017 (US$0.0935/kWh) made led rapid solar to installed PV expansion solar PV possible. capacity soaring fromSolar <100tari ffs at Vietnamese megawatts (MW) to more than 16,500 MW between 2018 and 2020. Rooftop projects drove a significant portion of the solar capacity growth, with capacity expanding from <400 MW to roughly over 9,700 MW between 2019 and 2020 (Vietnam Energy Partnership Group 2020). The updated 2018 wind FiT—at D 1,928/kWh (US$0.085/kWh) for onshore wind and D 2,223/kWh (US$0.098/kWh) for near-shore wind—similarly spurred growth, with the combined,Official Use Only domestic wind capacity leaping from <250 MW to over 5,000 MW between 2018 and 2022. With roughly 22 GW of combined wind and solar capacity in 2023, Vietnam exceeded the targets set under its previous power sector master plan (PDP7). Official Use Only 32 Philippines Initiatives such as the Green Energy Auction Program (GEAP), Green Energy Option Program (GEOP), Net- metering Scheme, and Renewable Portfolio Standards (RPS) have driven renewable energy growth in the Philippines. The FiT drove renewables growth between 2014 and 2019. The initial 50 MW target for solar was raised to 500 MW in 2014 due to strong interest, but still ended up being exceeded by 300 MW. FiT gave way to the launch of GEAP, a competitive auction process, in 2022. Over 10 GW of capacity have been awarded in the three completed rounds of the GEAP (figures 2.12 and 2.13). Renewable energy gets a considerable boost from the RPS also, which mandated an annual increase of 1 percent in renewables sourcing before 2023, followed by an increase to 2.52 percent. Figure 2.12 GEAP 1 Auction Capacities and Awarded Prices, June 2022 GEAP 1 June 2022 Auction Capacities and Awarded Prices Winning Bidders 140 0 Solar, 1350 12 Solar Philippines 10.36 Greenergy Solutions 120 0 9.70 9.85 9.88 10 9.13 Pavi Green Renewable Energy 8.35 Awarded Price (USD cents/kWh) 100 0 7.99 Bayog Wind Power1 7.56 8 Awarded Capacity (MW) 6.95 CleanTech Global Renewables 800 6.61 6.14 6.12 Capa Wind2 6 600 Petrowind Energy 4 Cordilera Hydro Electric Power 400 Hedcor3 2 Philnewriver Power 200 Solar, 99.98 Wind, 160 Wind, 100.8 Wind, 70 Hydro, 60 Biomass, Wind, 30 Solar, 40.4 Wind, 13.2 Hydro, 20 Cotabato Sugar Central Hydro, 19.15 3.4 0 0 Note: 1) Subsidiary of AC Energy Corporation (ACEN) Sol ar W ind Sol ar Sol ar W ind W ind W ind W ind Hydro Hydro Hydro Bi omas s Source: DOE 2) Joint venture of ACEN and Diamond Generating Asia 3) Susidairy of Aboitiz Source: Department of Energy. Note: Green Energy Auction Program. Figure 2.13 GEAP 2 Auction Capacities and Awarded Prices, July 2023 Winning Bidders Citicore Renewable Energy 500 12 Alternergy 10.41 10.52 10.44 450 10.35 Ixus Solar Energy 9.78 Acen 9.48 10 400 9.22 9.17 Enel Green Power 8.77 Gemini Energy Services 350 7.92 7.92 7.92 7.92 7.92 7.92 Awarded Capacity (W) 7.78 7.88 7.74 7.83 Awarded Price (USD cents/kWh) 7.56 7.62 8 First Maxpower International 7.37 7.17 7.38 6.98 Opus Philipines 300 6.47 PetroGreen Energy Corporation 250 6 Greencore Power Solution1 437.6 Vena Energy 200 380.4 NKS Solar2 362 4 ib vogt 150 274.7 Solar Valley 230 100 200 200 Xyris Energy 2 150 150 139.7 Meralco 125 50 90 90 80 79.0 70 Wyn Power Corporation 49.9 67.8 50 50 49 41.2 30.9 20 14 9.4 Cornerstone Energy Development3 0 0 Flo atin g Sol ar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Gro und Mo unte d So lar Ro oftop Sol ar W ind W ind W ind W ind W ind W ind W ind Power Philipines Megasol Energy Nuevasol Energy4 Solar Philipines Joy-Nostalg Solaris Note: 1) Joint venture of ACEN and Citicore 2) Joint Venture of Blueleaf and NKS Energy Utilities PHINMA Corporation Source: DOE 3) Joint venture of Cornerstone, Mainstream RE and Aboitiz 4) Joint venture of Vena Energy and Meralco Source: Department of Energy. Note: Green Energy Auction Program. Renewable Energy Integration in East Asia and Pacific 33 EAP countries offer policy support, alongside fiscal and nonfiscal incentives, that ease market entry for renewables. A conducive investment climate has channeled capital into VRE, spurring innovation and lowering costs. China’s approach spans national, regional, and local incentives, while relaxed foreign-ownership limits in Indonesia and the Philippines attract investment and signal commitment to the energy transition. China China’s incentives for VRE development span the national, regional, and local levels. The Renewable Energy Fund, financed through surcharges on electricity prices, provided support early in VRE development, now offering targeted subsidies for initiatives like zero-carbon parks and energy storage projects. Tax incentives, such as reductions or exemptions of value added tax (VAT) and income tax, are also provided, along with preferential tax rates. Certain regions offer import duty exemptions to VRE equipment manufacturers. The government also has a preferential land supply policy, for example, in Inner Mongolia and Xinjiang, where large-scale renewable energy projects are preferentially allocated land. Indonesia Indonesia encouraged entities engaged in renewable energy development through PR 112/2022, including, among others, favorable income taxes, land and building taxes, import duty exemptions, geothermal development support, and financing and/or guarantee facilities. The “Negative Investment List,” which imposed foreign ownership limits on power generation projects under 10 MW, was amended to enable 100 percent foreign ownership on projects above 1 MW capacity. Under the Ministry of Energy and Mineral Resources (MEMR) 11/2024, stringent local content requirements, which raised the costs of the domestic renewables ecosystem, were eased to attract investment. Electricity projects with at least 50 percent financing from multilateral or bilateral creditors are also deemed exempt from the local content rules. Vietnam Vietnam is among the more open developing economies in terms of foreign direct investment (FDI), supported by legal reforms to attract FDI, active participation in global trade arrangements, and consistent FDI inflows. Between 2015 and 2022, it was the second-largest developing-country market for renewable energy FDI. The government offers several financial incentives, including a preferential tax rate for 15 years from the year a project generates revenue; land-lease and tax exemptions for up to 3 years for fundamental construction; VAT incentives; and a 5-year import duty exemption for fixed assets, materials, and components. However, despite these incentives, Vietnam’s power sector, especially VRE, has attracted relatively limited FDI compared with other sectors. This is due to multiple issues with the bankability of domestic power purchase agreements (PPAs) and regulatory uncertainty. Foreign investors face imbalanced risk allocation, domestic-only arbitration, and no force-majeure definition in PPAs—constraints that have limited large-scale international participation in VRE development. Philippines The Renewable Energy Act of 2008 included, among other provisions, a 7-year income tax holiday, duty-free importation, accelerated depreciation, and VAT exemption to encourage renewable energy investment, and the government lifted foreign ownership restrictions in December 2022 to enable foreign investors to hold 100 percent equity in the exploration, development, and utilization of solar, wind, hydro, and ocean or tidal energy resources, to accelerate the transition. In the first 11 months of 2024, the sector received over P1.35 trillion in investments, marking a 48 percent year-on-year increase (Philippines Department of Trade and Industry). Official Use Only 34 2.6 Renewable Energy Expansion Needed to Fulfill Climate Ambitions Despite notable progress and some support, achieving net zero requires far more ambitious efforts.11 All the focus countries must deploy renewable energy faster, even China and Vietnam, where VRE capacity additions have grown significantly (to harness domestic reserves). While dispatchable sources such as hydro, geothermal, and biomass will be instrumental in and contribute to meeting climate goals, most future capacity additions are expected to be VRE. China needs to add more than 270 GW of renewable capacity every year to fulfill its net zero ambitions by 2060—meaning a roughly 670 percent increase in renewables’ capacity between 2023 and 2060. Under the World Bank’s Accelerated Decarbonization Scenario (ADS) 2040, VRE capacity reaches nearly 3,800 GW, requiring average capacity additions of 84 GW/year (solar) and 77 GW/year (wind).12 Under the Net Zero by 2060 scenario, solar and wind capacity exceed 10,800 GW, an increase of nearly 9,800 GW from the 1,050 GW capacity in 2023, or 9,400 GW from the 1,400 GW capacity achieved at the end of 2024. Total renewables capacity is expected to exceed 11,600 GW by 2060, requiring 273.2 GW of new additions every year from 2024 to 2060—an increase of nearly 120 percent over the 125.2 GW/year average between 2015 and 2023. Given the absence of 2050/2060 capacity targets in China’s national plans, ADS can anchor target-setting for 2040 and beyond. Figure 2.14 Renewable Energy Capacity Growth Renewable Capacity Growth Rate Total RE Potential 14,000 58,534 GW 12,000 11,613 GW 10,000 +166% (7,246 GW) 8,000 +190% (2,862 GW) GW 6,000 4,366 GW 4,000 2,000 1,505 GW 0 2023 2040 ADS 2060 NZ World Bank Solar Wind Hydro Bio Source: World Bank. Note: ADS = Accelerated Decarbonization Scenario; GW = gigawatt; NZ = net zero. 11 Renewable energy capacity growth rates required to reach net zero have been provided for all focus countries. Renewable energy capacity requirements for net zero have been sourced from existing national-level modeling and research studies: China from World Bank; Indonesia from IRENA; Vietnam from the Electricity and Renewable Energy Authority and Danish Energy Agency; and Philippines from Climate Analytics. The World Bank’s Accelerated Decarbonization Scenario assessments are limited to 2040, and therefore these additional studies serve as a substitute to forecast renewable capacity growth required to reach net zero. Refer to appendix D for details on renewable energy capacity and growth required to meet climate ambitions. 12 China’s VRE capacity additions exceed the growth rate required to meet the World Bank’s ADS 2030 scenario. ADS 2030 requires a wind and solar capacity of 1,630 GW by 2030 and 3,796 GW by 2040. With China achieving the 2030 target of 1,200 GW VRE six years ahead of schedule and attaining a VRE capacity of 1,400 GW at the end of 2024, the country is on track to achieve the ADS 2030 targets. Renewable Energy Integration in East Asia and Pacific 35 Renewable Capacity Growth Rate Total RE Potential 14,000 58,534 GW 800 Indonesia must scale up renewable capacity rapidly; more than 1,000 GW are required in a 2050 Net Zero 700 12,000 11,613 GW Scenario. Indonesia had 0.6 GW solar capacity and a mere 0.15 GW wind capacity as of end-2023. While PLN’s 600 most recent Electricity Supply Business Plan (RUPTL 2021–30) presents 10,000 a greener vision than its predecessors, +166% (7,246 GW) 500 (2 the next version 8,000 is expected to help build 75 +190% GW of renewables over the next 15 years, but it is not yet 400 GW (2,862 GW) GW finalized. The ADS scenario for Indonesia is much more ambitious, with 201 GW of additional renewables 6,000 300 capacity required up to 2040 (figure 2.15). IRENA’s “Indonesia 4,366 GWEnergy Transition Outlook” explores several net 4,000 zero scenarios assessing renewable energy shares of 85 percent, 90 percent, and 100 percent (IRENA 2022a). 200 For Indonesia to meet the most 2,000 ambitious 1,505 GW target of 100 percent renewable energy, the country must leverage 100 45.9 GW its considerable0 solar potential. This scenario would necessitate an installed solar capacity of 840 GW and a 0 wind capacity of 60 GW by 2050—with 2023 renewable energy 2040 capacity ADS additions of nearly 2060 38Bank NZ World GW/year between 2023 2024 and 2050. Solar Wind Hydro Bio Figure 2.15 Renewable Energy Capacity Growth Required in Indonesia Renewable Capacity Growth Rate Total RE Potential 3,828 GW 1,200 400 1,033 GW 1,000 350 +383% 300 800 (819 GW) +1,503% 250 (201 GW) 600 GW 200 + GW (1 400 150 214 GW 100 200 50 8.4 GW 13.4 GW 0 0 2023 2040 ADS 2050 NZ IRENA 2023 Solar Wind Geothermal Hydro Bio Source: World Bank and IRENA. Note: ADS = Accelerated Decarbonization Scenario; GW = gigawatt; NZ = Net Zero. For Vietnam to achieve net zero by 2050, nearly 22 GW of new capacity additions are needed every year, yielding a nearly 1,300 percent installed capacity growth up to 2050 from 2023. ADS 2040 for Vietnam requires adding just over 221 GW of capacity over 2024–40, with VRE capacity projected to contribute nearly 215 GW (figure 2.16). Vietnam’s recently revised Power Development Plan 8 (RPDP8) targets are much more ambitious than the last version and target 111.4 and 526.1 GW of VRE capacity by 2030 and 2050, respectively.13 The Danish Energy Agency’s net zero scenario for Vietnam also calls for a ramp-up of VRE (EREA and DEA 2024). Solar and wind capacities are projected to reach 406 and 196 GW by 2050, respectively, under this scenario.14 To meet these targets requires solar capacity additions of 7.5 GW/year on average from 2025 to 2030, 9 GW/ year between 2031 and 2040, and peak at 27 GW/year from 2041 to 2050, and wind capacity addition of 7.1 GW/year on average between 2024 and 2050. 13 The 2050 RPDP8 targets considered in this report exclude the additional 240 GW of offshore wind capacity planned for “new energy” since its exact use in power generation remains unclear. 14 This report references the Net Zero Scenario as opposed to the Net Zero+ Scenario—with the latter requiring lower renewable energy capacity on account of nuclear power. Official Use Only 36 Figure 2.16 Renewable Energy Capacity Growth Required in Vietnam Total RE Potential Renewable Capacity Growth Rate Total RE Potential 58,534 GW 800 1,833 GW 700 +116% 11,613 GW 636.4 GW (309 GW) +10% 600 576.2 GW (60 GW) +483% ) 500 (221 GW) 400 GW 300 267.3 GW 200 100 45.9 GW 0 2060 NZ World Bank 2023 2040 ADS 2050 RPDP8 2050 NZ DEA Solar Wind Hydro Bio Total RE Potential Renewable Source: World Bank, Electricity and Renewable Capacity (EREA), Energy Authority Rate Growthand Agency Danish Energy Total (DEA). RE Poten tial 58,534 GW Note: ADS = Accelerated 800 Decarbonization Scenario; GW = gigawatt; NZ = Net Zero; RPDP8 = Vietnam’s 1,833 GW Revised Power Development Plan 8. Total RE Potential 700 +116% Total RE Poten tial 11,613 GW Renewable Capacity Growth 636.4 GW (309 GW) Rate +10% 3,828 GW 600 576.2 GW 597 GW The Philippines (60 GW) to align with 400needs to add more +483%than 13 GW of capacity every year between 2024 and 2050 1,033 GW 500 361.3 GW a Climate Analytics’ 350 1.5°C compatible (221 GW)pathway, boosting installed capacity by 4,200 percent (Climate Analytics 2023). VRE capacity 400 additions must grow rapidly under the ADS 2040 for the Philippines—rising from 2.1 GW 300 +215% ) GW in 2023 300to nearly 92 GW by 2040 (figure 2.17). 267.3 GW The Reference Scenario (246 in GW)the Philippine Energy Plan (50 250 percent renewables 200 +1,227% by 2040) emphasizes solar energy, while wind energy is expected to share in generation +3% 200 GW (3.5 GW) be relatively100 more instrumental (103in meeting GW) the Clean Energy Scenarios, CES115 (65 percent renewables share 150 45.9 GW 111.3 GW 114.8 GW in generation by0 2050) and CES2 (70.7 percent renewables share in generation by 2050). However, renewables 100 2060 NZ World Bank capacity under the Climate 2023Analytics’ Net 2040Zero by 2050 scenario ADS is three times as 2050 RPDP8 2050much as under CES1, NZ DEA 50 8.4 GW requiring higher capacity targets and faster capacity Solar additions Wind to stay Hydro Bio aligned with the Paris Agreement goals. 0 2050 NZ IRENA 2023 2040 ADS Figure 2.17 Renewable Energy Capacity Growth2050 CES1 Required 2050 NZ Climate Analytics in the Philippines io Solar Wind Geothermal Hydro Bio Total RE Potential Total RE Potential Renewable Capacity Growth Rate 3,828 GW 597 GW 400 1,033 GW 361.3 GW 350 300 +215% (246 GW) 250 +3% 200 +1,227% GW (3.5 GW) (103 GW) 150 111.3 GW 114.8 GW 100 50 8.4 GW 0 2050 NZ IRENA 2023 2040 ADS 2050 CES1 2050 NZ Climate Analytics Source: World Bank and Climate Analytics. Solar Wind Geothermal Hydro Bio Note: ADS = Accelerated Decarbonization Scenario; CES = Clean Energy Scenario; GW = gigawatt; NZ = Net Zero. 15 This report uses the CES1 scenario of the Philippine Energy Plan as the national plan. The CES1 scenario follows a balanced approach between solar and wind energy as opposed to the Reference Scenario (solar focused) and CES2 scenario (wind focused). Barriers to VRE Scale-up in the Focus Countries 37 3. Barriers to VRE Scale-up in the Focus Countries Building on the analytical framework underlying this report, this chapter examines the key barriers to expanding variable renewable energy (VRE) across the focus countries. Some challenges are common, but each market has a distinct mix; we present overarching constraints with country-specific manifestations. The analysis is organized under four enabling pillars addressing the energy trilemma—energy security, affordability, and decarbonization. Challenges within these pillars are intertwined and closely linked to the project-level implementation hurdles often cited by the private sector. Table 3.1 Summary of Barriers to VRE Scale-up in EAP Energy Security, Energy Affordability, and Energy Sustainability 2. Enabling Policies, 1. National Ambition Regulatory Frameworks, 3. Infrastructure and 4. Financing and and Renewable Energy and Supporting System Operations Investment Climate Target Planning Initiatives System planning Investment climate Power system High up-front costs, does not adequately is hindered by operation has not underdeveloped account for new opaque procurement transitioned from financial markets, demand drivers processes, lack of dispatchable and firm and insufficient and distributed clarity on competitive generation and lacks institutional generation potential, auctions, and network and grid investors—limiting required targets for imbalanced risk flexibility measures access to optimized transmission network allocation in PPAs to unlock domestic sources for funding and ancillary services, leading to higher and regional VRE the energy transition and investment needs financing costs and integration for adaptation and reduced investment resilience measures commitment Predominantly Predominantly Surfaces as a barrier Predominantly surfaces as a barrier surfaces as a barrier in all nascent, surfaces as a barrier in nascent and in nascent and transitioning, and in nascent and transitioning markets, transitioning markets, advanced markets transitioning markets, with only limited gaps with negligible gaps in with only limited gaps in advanced markets advanced markets in advanced markets Note: Refer to appendix E for details on secondary barriers to VRE scale-up in the focus countries. EAP = East Asia and Pacific; PPA = power purchase agreement; VRE = variable renewable energy. Official Use Only 38 Pillar 1. System planning does not adequately account for new drivers of economic growth, distributed generation, VRE integration, and infrastructure resilience National and renewable energy targets across the EAP region are often set in isolation from the broader system planning for transmission, system flexibility, and investment. Generation plans also fail to fully account for future demand drivers—industrial decarbonization, e-mobility, digitalization, data centers, and adaptation, among others. Weak coordination between VRE capacity additions and the required grid upgrades and flexibility (e.g., ancillary services) slows sector growth and progress toward national targets. National plans often understate the potential of distributed renewable energy (DRE)—such as rooftop solar photovoltaic (PV) on industrial, commercial, and residential buildings—while utility-scale projects dominate targets. DRE also faces obstacles in terms of limited rooftop installation spaces, particularly in high-rise buildings, regulatory obstacles to the sale of excess electricity to grids, and a lack of viable business models. Robust DRE assessments are rare, and transparency is limited on how targets are set, including resource assessments, cost assumptions, and demand-forecast methods. This weakens investor confidence and, in some markets, yields targets that are either unambitious or unrealistic, given infrastructure and financing constraints. While all focus countries have submitted ambitious Nationally Determined Contributions (NDCs) and climate targets, national power sector plans usually lack related targets. More specifically, there is no explicit link between emissions reductions in the power sector and NDCs, making it difficult to assess the sector’s contribution to national goals. At the same time, despite high climate vulnerability, the investment requirements of adaptation measures—decentralized generation, grid modernization (e.g., microgrids, smart grids), and infrastructure resilience (e.g., water management, flood and storm-resistant structures, site retrofitting, reinforcement)—are often missing from power-sector master plans, hindering timely upgrades. Industrial decarbonization via electrification will rely on renewable energy, green hydrogen (itself powered by renewables), energy-efficiency improvements, and carbon capture, use, and storage (CCUS). World Bank modeling indicates sharp demand growth in China, Indonesia, and Vietnam: China’s industrial electricity use rises 77 percent by 2050, with 10.5 percent from direct electrification and the remainder for green hydrogen (2,956 terawatt-hours [TWh] by 2050); Indonesia’s industry reaches 368 TWh by 2050, nearly sixfold its 63 TWh in 2022; and in Vietnam, electricity needs increase by about half to decarbonize industry and nearly fourfold for the rest of the economy by 2050. These increases are not yet reflected in national power plans or renewable capacity targets, and emerging loads from transport electrification, data centers, and cooling are generally excluded—creating a growing gap between future electricity needs and planned renewable capacity, with risks of underinvestment, delayed infrastructure, and compromised energy security. Power systems across EAP are marred by weak links between national plans and sectoral planning. The plans often inadequately account for new demand drivers and investment requirements for network upgrades and infrastructure resilience (generation, transmission, distribution, and ancillary services), limiting VRE system expansion and integration. Barriers to VRE Scale-up in the Focus Countries 39 Pillar 1. Market-specific Challenges Indonesia’s renewable energy planning faces systemic challenges stemming from fragmented governance, misaligned policies, and conflicting institutional mandates. These issues manifest most acutely as (i) inconsistent long-term decarbonization pathways; (ii) overlapping agency responsibilities; and (iii) a de facto preference for utility-led planning over nationally harmonized strategies. Targets are also misaligned over time: while short-term goals are consistent across KEN, RUEN, and the 2021—30 RUPTL—each aiming for 23 percent renewables by 2025—long-term targets diverge significantly. 16 In Vietnam, the Power Development Plan 8 (PDP8) was delayed three years due to weak demand estimates and least-cost generation planning. It was revised again in April 2025 to reflect revised socioeconomic targets, updated demand projections, and implementation delays across major projects, including VRE and transmission. The update reintroduces nuclear power and significantly raises VRE ambition: combined solar PV and wind capacity increases by almost 130 percent, alongside a required sevenfold increase in storage targets. Alignment of transmission upgrades and planning with these VRE targets remains unclear. The planning delay has paused what was EAP’s most active VRE market, and continued waiting for the implementation plan pressures target achievement and creates uncertainty about the sector’s long-term direction. Pillar 2. Policy and regulatory uncertainty limits investor confidence and investments in EAP VRE growth in EAP continues to be limited by a lack of supporting regulatory and policy reforms, uncertainty and lack of transparency on procurement, and concerns with the bankability of power purchase agreements (PPAs). While some countries have moved from administratively set feed-in tariffs toward market-based pricing and allowed limited corporate PPAs, the transition has been slow, uneven, and marked with regulatory gaps and policy uncertainty. Lack of clear and consistent regulations, changes in local content requirements, and frequent revisions and delays in finalizing VRE targets prevents commitments on long-term project development pipelines. A hazy procurement process—lack of visibility in auction schedules and timelines, inconsistent procurement volumes, and volatile pricing—compounds the challenges. Concerns over PPA bankability restrict access to cheaper international capital, forcing developers to rely on higher-interest debt and raise larger equity shares when long-term financing is unavailable. This increases the weighted average cost of capital, reduces bankability, raises risk premiums and overall costs, and ultimately slows the energy transition. Lack of supportive and enabling regulatory frameworks such as competitive auctions, uncertain procurement schedules and volumes, and concerns over PPA bankability contribute to higher risk premiums and financing costs, hindering investment and optimal VRE scale-up in the EAP region. 16 Refer to appendix E for a summary table on differences in renewable energy targets across policies in Indonesia. Official Use Only 40 Box 3.1 Private Sector Feedback: Challenges with China’s Subsidy Program Since the 2021 subsidy phaseout, newly commissioned variable renewable energy projects use market- based pricing, but legacy projects still face delayed subsidy disbursements. Backlogs across wind and solar have eroded projects’ internal rates of return, with impacts varying by region. Although the government has piloted securitization of renewable receivables, cash-flow verification and local- government guarantee requirements continue to impede solutions. Challenges with China’s Local Content Requirements Foreign investors face structural barriers in China’s renewables: domestic-content and technology- transfer rules raise costs versus local firms, and SAFE capital controls require QFLP approval, adding 6–9 months to timelines. The 2023 Capital Account Facilitation Policy eases some frictions by allowing foreign-invested enterprises in pilot zones to make cross-border yuan settlements without prior quota approvals; early adopters report lower FX hedging costs via the new renewable-energy derivatives window at the China Foreign Exchange Trade System. In Indonesia, VRE procurement is affected by tenders being infrequent and often delayed, undermining investors’ confidence and stalling project pipelines. Although Presidential Regulation (PR) 112/2022 formalizes two primary procurement mechanisms—(1) direct appointment, which allows Indonesia’s state electricity utility (Perusahaan Listrik Negara, PLN) to appoint and negotiate directly with independent power producers (IPPs), and (2) direct selection, a competitive bidding process where PLN selects the IPP offering the best price, their actual implementation is largely opaque and often open to speculation on the selection of IPPs. VRE auctions in Indonesia also lack a procurement schedule—leading to sparse and irregular auction rounds. PLN has conducted procurements for far less capacity than what is called for in the RUPTL, leaving numerous projects listed in the RUPTL without any procurement activity to date and creating uncertainty and undermining the investment in development activities for VRE projects. Box 3.2 Private Sector Feedback: Challenges with Indonesia’s Renewable Energy Procurement Stakeholders cite unclear project pipelines and procurement uncertainty as major obstacles to solar and wind development in Indonesia. Despite abundant potential, the lack of a predictable tender schedule discourages establishing local teams. Participation is limited to prequalified investors on the List of Selected Providers (Daftar Penyedia Terseleksi, DPT), yet it is not transparent whether all listed developers are invited. Tender evaluation criteria and results are not publicly disclosed, forcing stakeholders to rely on industry networks for information. Beyond procedural opacity, restrictive requirements deter private investment. PLN often mandates that its subsidiaries hold a 51 percent stake in project companies, and developers are sometimes expected to finance part or all of PLN’s equity—reducing developer control and depressing equity returns. Local content requirements are difficult to meet given underdeveloped domestic manufacturing and supply chains, which are largely a result of a limited project pipeline. It has been noted that Indonesia’s solar industry has not yet matured to produce tier-1 modules, a key requirement for investors and lenders. Although intended to support local industry, these rules raise costs and hinder renewable energy investment as they tend to increase costs. Barriers to VRE Scale-up in the Focus Countries 41 Indonesia’s procurement framework is hindered by a lack of transparency and predictability, with infrequent and delayed tenders, opaque implementation of formalized procurement mechanisms, and restrictive requirements that undermine investor confidence and stall project development. In Vietnam, frequent policy revisions and implementation delays have eroded investor confidence. The long absence of finalized tariff brackets under the Ministry of Industry and Trade’s (MOIT’s) competitive selection scheme created prolonged regulatory uncertainty; brackets have been proposed but not yet approved, marking a significant delay this year. Beyond setting viable tariff levels, the annual tariff-ceiling process must be expedited to restore visibility. Zero floor prices and unfavorable PPA terms have further deterred investors, prompting a wait-and-see approach. Uncertainty also surrounds procurement under PDP8. Although Decree 115 introduces competitive bidding for VRE, the decree and related policies lack clarity on ceiling tariffs, detailed selection criteria, and draft PPAs, rendering implementation ambiguous. This uncertainty has led several notable international investors to exit the market across solar, onshore wind, and offshore wind. Vietnam’s standard PPA places disproportionate risk on investors and lacks protections needed for international finance at scale—no government guarantees or credit support for Electricity Vietnam (EVN) payments, no change-in-law protection, no curtailment protection, no offshore arbitration, and weak lender- rights recognition. International lenders view these terms as unbankable, limiting access to nonrecourse financing; most deals rely on domestic or sponsor-backed funding, with a few DFI/ECA-supported exceptions linked to European equipment. The current PPA risk allocation model is also not fit for purpose as Vietnam moves into its next phase of VRE development. Without reforms, the country will struggle to mobilize the level of private capital required to meet the revised PDP8 targets, particularly for offshore wind, where financing needs are substantially higher and investor risk tolerance is lower. Box 3.3 Private Sector Feedback: Challenges with Vietnam’s PPA Bankability Private sector feedback highlights that Vietnam’s variable renewable energy (VRE) power purchase agreements are widely perceived as nonbankable in the international debt market. Key concerns include inadequate investor and lender protections related to curtailment, termination, force majeure, and change-in-law provisions. The removal of US dollar–linked tariffs further exacerbates risk by creating a cost-revenue mismatch, as project capital expenditures remain denominated in US dollars. While domestic banks have been willing to lend based on the Electricity Vietnam’s (EVN’s) template power purchase agreement, they have done so with corporate guarantees during the construction phase. Between 2017 and 2021, the majority of VRE projects were financed through domestic banks in Vietnamese dong, which exposed these projects to considerable exchange rate risks, particularly fluctuations between the US dollar and dong. Given this context, questions have arisen regarding the capacity of the domestic financial market to absorb further risk, especially considering the much larger capital requirements for offshore wind projects. Vietnam’s frequent policy revisions, delays in tariff approvals, and lack of clarity in the procurement process have collectively eroded investor confidence and stalled project development. Inadequate protection for investors in the template PPA further exacerbates financial risks and limits access to international financing. Official Use Only 42 While 10 GW of new capacity were awarded in three rounds of the Philippines’ Green Energy Auction Program (GEAP), participation has been impacted by auction design characterizing low price caps, grid connection uncertainty, and PPA bankability concerns. The Renewable Energy Payment Agreement (REPA)—the PPA under GEAP auctions—is generally considered bankable by domestic and international financial institutions, but industry stakeholders express concerns over the REPA template lacking adequate risk allocation (issued by the Energy Regulatory Commission [ERC]), particularly in the context of offshore wind. Key issues include insufficient protection against curtailment, lender’s step-in rights, and an inadequate termination clause— all of which deviate from international standards. Developers are left exposed to potential revenue risks and operational uncertainties, affecting the long-term bankability of offshore wind projects. Box 3.4 Private Sector Feedback: GEAP Shortcomings in the Philippines Developers quote that low ceiling prices set in the second Green Energy Auction Program (GEAP 2) led to over 8,000 megawatts, or nearly 70 percent of the capacity to remain unsubscribed. Another major factor contributing to the low turnout in the GEAP was the lack of timely access to transmission lines. Developers cite stringent performance bond requirements as a key barrier in the GEAP 2 auction. Although reduced from 20–30 percent of project cost to 5 percent, the bond remains burdensome for smaller developers, forcing partnerships with larger firms or withdrawal. They also recommend a more technology-agnostic design—for example, permitting battery storage alongside pumped hydro—to broaden participation. The region’s unclear regulatory frameworks also limit project innovation and growth of new technologies. Except for the Philippines, the focus countries lack regulatory frameworks that allow short-or long-duration battery storage to participate in wholesale or ancillary services markets. Absent a defined role and pricing, developers face monetization uncertainty. In Indonesia and Vietnam, storage is not recognized as a grid asset or market participant, constraining investment; in Vietnam, ancillary services are largely supplied by hydropower. Box 3.5 Private Sector Feedback: Project Implementation Challenges In China, small and medium enterprises face mounting challenges as state-owned enterprises (SOEs) and provincial SOEs now account for over 70 percent of newly installed capacity. Structural factors— preferential access to grid connections, lower financing costs via policy banks, and economies of scale in equipment procurement—reinforce this dominance. National planning policies can deepen the imbalance: several renewable energy bases prioritize large, centralized SOE-led projects, sidelining distributed systems favored by SMEs that struggle to secure land permits and grid access in remote areas. Private developers also face delays in grid approvals under the 2023 Renewable Energy Operation Standards, which require certifications and Environmental Impact Assessments (EIAs). Permitting delays and inefficiencies continue to hinder variable renewable energy (VRE) deployment across East Asia and Pacific, though severity varies by country. In Vietnam, approvals are complicated and time-consuming, often requiring consultations with multiple national and provincial agencies. The absence of clear written guidance and differing provincial requirements create confusion and delay. Similarly, in Indonesia, unclear requirements and opaque, multi-agency decision-making add costs and prolong timelines, undermining investor confidence. Barriers to VRE Scale-up in the Focus Countries 43 In the Philippines, the Department of Energy’s 2019 Energy Virtual One-Stop Shop (EVOSS) has reduced permitting lead times but is not yet a true one-stop system. Developers must still obtain multiple permits and licenses from local government units (LGUs), agencies, and bureaus (WWF 2023)—often from the same offices at different stages—creating unwarranted delays. Securing a grid-connection permit also remains time-consuming, leaving developers uncertain about when projects can begin delivering power. A backlog of system impact studies (SIS) at the National Grid Corporation of the Philippines (NGCP) continues to slow development. Because SIS are required to assess grid viability the backlog has created uncertainty for participation in the Green Energy Auction Program and has delayed projects. Developers report timelines of up to 18 months for the NGCP to complete an SIS (OECD 2024). Land acquisition is a pervasive constraint for large-scale solar and wind projects, causing setbacks, higher development risks, and increased costs. Processes are lengthy and involve multiple government tiers with divergent requirements. This challenge arises from the lack of large, contiguous land parcels and the need to negotiate with multiple small landowners. Inadequate land record management often causes further delays in the process as new landowners emerge with competing claims. In Indonesia, the land acquisition process is lengthy and complex due to unclear land titles and overlapping claims. Only about 35 percent of land—mostly urban—is registered, and many Indonesians hold informal rights (OECD 2021). Developers must navigate national, regional, and local frameworks, including approvals from the Ministry of Environment and Forestry for state forest land (about two- thirds of the country) followed by location permits from local authorities. These multiple approvals and bureaucratic hurdles create significant delays. In Vietnam, converting agricultural land is difficult and slow, requiring engagement with local landowners and provincial People’s Committees. Because all land is state owned and prices are tightly regulated, securing land-use rights can be costly, especially where ownership is fragmented. Public consultations add complexity and extend timelines. International investors have called for clearer, more efficient processes and a more proactive provincial role in mediating negotiations among developers, landowners, and communities. Developers in the Philippines also report delays in obtaining land-use conversion approvals, particularly when agricultural land is involved. The process requires approval from the Department of Agrarian Reform, and some projects face prolonged timelines due to procedural hurdles. While not widespread, these delays add uncertainty and can affect the feasibility of large-scale projects. Pillar 3. Traditional transmission infrastructure and power system operations limit VRE integration VRE’s intermittency manifests as integration risk, inflates risk premia, and increases transition costs. Aligning VRE additions with system capacity is essential. At low shares the impact is small, but higher shares face grid- connection queues, congestion, and curtailment—delaying new capacity, undermining existing integration, and weakening returns and investor appetite. Risks are amplified by plants sited far from demand centers; uncertainty around curtailment, delivery, and congestion further widens the risk premium. In EAP, grid issues are acute given reliance on dispatchable, firm generation. China and Vietnam have seen technical curtailment from inadequate transmission. In China, wind and solar curtailment reached 3.6 percent Official Use Only 44 and 2.8 percent in January–August 2024 (up from 2.7 percent and 2.0 percent in 2023, respectively), exceeding 5 percent in several northern and western provinces (S&P Global 2024a). Vietnam experienced congestion and major curtailments in solar-heavy Ninh Thuan and Binh Thuan, with 365 million kilowatt-hours (kWh) curtailed in 2020 (Vietnam Express International 2021). Transmission network expansion has lagged rapid renewable deployment. China leads in UHV development, with 38 lines operating as of April 2024 and more than US$220 billion (BBC 2024) invested by August 2023, yet curtailment persists amid record VRE growth. In Vietnam, slow grid upgrades have temporarily halted utility- scale projects under PDP8. Some 110 kilovolt lines (e.g., Vinh Son–Hoai Nhon, Vinh Son–An Khe) are degraded or congested (McKinsey 2023), making them unsuitable to transmit and handle VRE. Infrastructure upgrades in Vietnam are further complicated by the need to connect concentrated VRE sources in the central and south- central regions to load centers in the north. Grid issues across the focus countries are further exacerbated by the lack of participation of battery storage assets in ensuring system flexibility. Intermittency exposes grids to frequency and voltage swings and heightens curtailment risk. Fast-responding batteries are essential for a VRE-heavy system—including for black-start capability—even as they add to transition costs. Effective markets require VRE targets and siting grounded in transmission assessments, clear ancillary-services and storage rules, and financing provisions for grid investment—gaps that persist across nascent, transitioning, and advanced EAP markets. Regional integration is also hampered by incompatible grid codes and standards. The absence of Automatic Generator Control and weak frequency regulation in several systems create inefficiencies that can propagate through interconnectors. While synchronous high-voltage links could expand power trade, uneven grid stability delays feasibility. HVDC interconnections offer an alternative but entail higher costs and technical complexity (ADB 2023). Grid congestion and curtailment issues are prevalent because transmission infrastructure is inadequate and ancillary services do not utilize battery storage systems. Aligning grid capabilities with rapid VRE deployment remains challenging, and inconsistent grid codes and standards constrain regional integration and operational efficiency. Pillar 3. Market-specific Challenges Grid flexibility is further hindered by the absence of an ancillary services framework in most EAP countries— a policy and regulatory gap. In China, the recent scrapping of the storage mandate for VRE projects (PV Magazine 2025) adds uncertainty. High capital costs, combined with no clear pricing and dispatch mechanisms, leave battery projects commercially unviable. China’s ancillary services market remains dominated by peak shaving (Zhang, Fan, and Lv 2023), and because local governments design these markets, provincial compatibility is uncertain. Without fair compensation for reserve capacity and services such as frequency control, voltage regulation, and peak shaving, grid stability will weaken as additional VRE comes online. Fragmented provincial planning and trading impede VRE integration. Planning, operations, and reserve margins are set at the provincial level, allowing provinces to add coal capacity to meet peaks. VRE resources are concentrated in the north and northwest. Coal production is prevalent in Shanxi, Shaanxi, and Inner Mongolia, while major load centers are in the east and south. The market provides weak incentives for the construction of new grid networks from VRE-concentrated regions to coastal demand centers. Interprovincial trade volume remains limited, and provinces trade through annually negotiated, unidirectional long-term contracts at regulated prices, lacking equal, open grid access for renewables. Without coordinated, cross- province development of VRE, thermal capacity, and networks, curtailment is likely. Barriers to VRE Scale-up in the Focus Countries 45 China’s recent decision to scrap its energy storage mandate for VRE projects has created uncertainty in power system flexibility. High investment costs and a lack of pricing mechanisms render battery storage commercially unviable. Further, inconsistent provincial planning hinders effective integration of VRE concentrated in the north with demand centers in the east and south, leading to potential grid instability and increased curtailment risks. Indonesia’s archipelagic geography and mountainous terrain separate generation from load, complicating grid expansion and destabilizing voltage and frequency. Some island grids—especially Java-Madura-Bali (Jamali) and Sumatra—see oversupply, whereas others face persistent undersupply due to limited investment in generation capacity (Energy Transition Partnership 2023). Sparse interconnections among island systems further constrain integration efforts. Ancillary services, notably frequency control, are undervalued and handled solely by PLN outside of a market-based framework. The absence of clear pricing mechanisms and regulatory frameworks for energy storage and ancillary services makes for little incentive to finance grid flexibility. The fully state-owned transmission system has constrained expansion because grid development depends mainly on PLN’s financial capacity. PLN’s expansion strategy does not align with Indonesia’s renewable energy and decarbonization goals, nor does it account for the expected electrification of sectors such as transport and industry. Although private operators may develop transmission and distribution via build-operate-transfer or build-lease-transfer contracts, the network remains inadequate for VRE integration. However, Indonesia has since announced plans to lead the development of a “supergrid” to unlock inter- and intra-island connectivity. In the Philippines, grid-capacity-related concerns, especially for offshore wind, stem from NGCP’s weak incentives to upgrade and ERC’s strict cost controls, which limit profitability and slow expansion. Dispatch of new solar and wind is constrained by delayed projects: by 2024, the NGCP had completed only 29 percent of targeted projects (75 of 258) (Power Philippines 2025); nearly 75 percent (58 planned projects) are delayed, some by more than nine years, and the Mindanao-Visayas Interconnection Project was eight years late (Rappler 2024). Right-of-way (ROW) issues slow down project implementation—the NGCP reports that ROW issues cause delays in over half its projects, with 115 applications pending at the ERC. Resistance from private landowners, slow writs of possession, and complex permitting across local government units, regional development councils, and national agencies (e.g., the Department of Energy) further impede grid expansion. In the Philippines, slow progress on ROW issues for transmission grid upgrades and complex multiagency permitting have caused significant project delays, raising concerns about the grid’s readiness to integrate increasing VRE shares. Pillar 4. Limited financing and investment constraints hinder the future of energy transition in EAP EAP will have to bear significantly more expenditure for the energy transition if PPA bankability risks, regulatory risks, integration risks, and such, are unaccounted for. The transition also imposes costs from stranded assets. With some of the youngest coal fleets, focus countries face high expenses to retire coal mines and power plants during the transition. Most of the EAP region lacks access to the scale of capital required, and mobilizing low-cost finance to meet sector affordability goals remains a core challenge. Official Use Only 46 Box 3.6 Global Financial Headwinds are Exacerbating Investment Challenges High up-front costs and 50–60 percent gearing expose variable renewable energy (VRE) developers to interest rate risk. Since 2022, global rate hikes—except in China—have raised capital costs and eroded returns, reversing prior cost declines, especially for offshore wind. A 2 percent rise in the risk-free rate lifts renewable levelized cost of energy by 20 percent (WEF 2024). Between 2020 and 2023, VRE debt costs rose from 1.9 to 7.5 percent in North America and from 1.4 to 6 percent in Western Europe (Oxford Sustainable Finance Group 2024). Large developers’ interest expenses jumped 30 percent year on year in 2023, driving losses and cancellations at GE Vernova and Ørsted (S&P Global 2024b). In 2023, 15 GW of offshore wind in the United States and United Kingdom was canceled or postponed; European solar and wind auctions went unsubscribed and smaller developers went bankrupt. Expected equity internal rate of return for US utility-scale solar climbed to 8–9 percent in 2023—about half of what foreign developers require in emerging and developing economies (IEA 2024c). Financing pressures have been compounded by rising equipment costs—mostly onshore and offshore wind and partly solar photovoltaic—driven by inflation (IEA 2024d). Mounting financing costs have triggered cancellations, asset write-downs, and reduced activity. These strains are visible in East Asia and Pacific: Ørsted paused offshore wind in Vietnam over cost and regulatory concerns, and other global players are scaling back in emerging markets. While interest rate cuts may aid bankability, but uncertainty persists. Policy actions—better auction design, faster and simpler permitting, and stronger grid integration—are needed to reduce risk and improve returns. Under the 2040 Accelerated Decarbonization Scenario (ADS), the power sectors in the focus countries require approximately US$9 trillion in new assets between 2020 and 2040 (undiscounted, combined)—roughly 40 percent higher than the requirements under the Current Policy Scenario (CPS) of the Country Climate and Development Reports (CCDRs) (World Bank 2025). Total system costs—transmission, grid upgrades, storage, and system balancing for VRE—further raise investment. According to World Bank CCDRs, Vietnam, Indonesia, and the Philippines need nearly US$335 billion in incremental generation and transmission (undiscounted) in 2020–40 under ADS versus CPS. Rising distributed resources (rooftop solar, batteries) also demand parallel distribution investments—capacity upgrades, metering, substations, feeder lines for bidirectional flows—and planning for new supply and demand from decentralized uses (e.g., electric vehicles and heat pumps), all of which increase total system costs. These increases are projected to raise the levelized cost of energy (LCOE) in Indonesia, Vietnam, and the Philippines by about 16 percent on average relative to the CPS. If all incremental system costs are passed through to the consumers, electricity prices could see an increase of up to 20 percent by 2040. In the Philippines—where tariffs are already among the highest in the Association of Southeast Asian Nations—tariffs burden households (CDN 2024) and could threaten economic goals (GMA 2024), so further increases to enable pass-through may trigger public opposition. Barriers to VRE Scale-up in the Focus Countries 47 Figure 3.1 Additional Investments—Generation and Network, 2020–40 Generation & Network Costs (2020-2040) 400 350 300 250 US$ Bn 200 Network Generation 150 100 50 0 CP S ADS CP S ADS CP S ADS Vietnam +73% Indonesia +53% Philippines +122% Source: World Bank. Note: ADS = Accelerated Decarbonization Scenario; CPS = Current Policy Scenario. While China’s domestic financial markets can fund the energy transition, equity fundraising faces challenges, as indicated by the private sector. Domestic financial markets’ ability to fund the energy transition in Indonesia, Vietnam, and the Philippines is under question. Box 3.7 Private Sector Feedback: Challenges with Equity Fundraising in China Equity fundraising faces challenges, subject to more requirements than required for conventional debt financing. China now follows stricter regulatory scrutiny for equity transactions, including stringent Environmental Impact Assessments and grid compliance certifications, for full compliance with its 2023 Renewable Energy Operation Standards. Private developers continue to have limited access to green finance initiatives, such as carbon-neutrality-linked loans. Box 3.8 Assessing Vietnam’s Domestic Credit Capacity for the Energy Transition Vietnam’s Revised Power Development Plan 8 (RPDP8) outlines an investment requirement of almost US$136 billion between 2026 and 2030 and approximately US$700 billion between 2031 and 2050 to achieve the Plan’s targets. However, implementation faces potential threats from issues with the financing landscape, especially given the domestic banking sector has limited depth, local capital markets are constrained, and state-owned utilities have deficient creditworthiness. Domestic Banking System Limitations The banking sector has a structural asset–liability mismatch that constrains long-term lending. As of late 2023, 88 percent of deposits matured in under 12 months, while 52 percent of loans were medium and long term, according to the State Bank of Vietnam. Circular No. 08/2020/TT-NHNN (“Circular 8”) caps the share of short-term funding used for medium- and long-term loans (“STFML”) at 30 percent (SBV 2023). The real estate sector already accounts for about 20 percent of total credit and is expected to maintain that share (SBV 2024a). With the STFML ratio at 28.32 percent in November 2024 (SBV 2024b), headroom for long-tenor power sector lending is limited without breaching the cap. Nonperforming loans are rising—especially in real estate—amid regulatory tightening and a corporate bond market crisis. Tighter credit and slowing sales have strained developers’ cashflow, worsening banks’ asset quality, which is further undermined by thin capitalization and ongoing asset-liability mismatches. Official Use Only 48 Local Capital Market Limitations Vietnam’s local debt market faces structural and regulatory barriers that limit its role in infrastructure finance. In 2019–21, renewable firms typically issued 7–8. Many of these bonds related to transitional projects had their maturities reduced to 3 to 4 years due to cash flow issues from the lack of electricity pricing mechanism (FiinRatings 2023). This deepens the mismatch with 10–15 year project paybacks and raises refinancing risk. Market depth is further constrained by Clause 2, Article 99 of Law No. 08/2022/QH15 on Insurance Business (Government of Vietnam 2022), which bars insurers from buying bonds issued for debt restructuring or refinancing; ambiguity around these terms prompts many institutions to avoid such bonds entirely. Additional demand-side headwinds include falling retail investor confidence and regulatory limits on institutional investors. Credibility has also been damaged by real-estate bond fraud, ongoing investigations, and Electricity Vietnam’s (EVN’s) tariff renegotiations in renewable projects. Payment delays by EVN have compounded stress. By December 2023, at least 15 renewable firms had postponed interest payments; BCG Energy and Trung Nam Dak Lak 1 sought extensions citing unpaid electricity revenues (Vietnam Express International 2023). These delays—together with transitional- project issues and EVN compliance probes—have driven a rise in bond events. As of April 2025, defaults or restructurings reached Vietnamese dong 28.9 trillion across 18 issuers, typically via missed interest or “successful extensions” negotiated with bondholders. Creditworthiness of the State-owned Utility Meeting RPDP8’s investment needs hinges on domestic actors—especially state-owned enterprises such as EVN, which account for over half of the power sector’s credit exposure. EVN’s borrowing capacity is constrained by two rules: the 2024 Law of Credit Institutions lowers single-borrower exposure limits from 25 percent to 15 percent of a bank’s regulatory capital by 2029; and EVN’s liabilities-to-equity ratio is capped at three times (it was 2.3 at end-2023), limiting headroom. World Bank estimates put EVN’s borrowing capacity at US$20 billion by 2030 and US$63 billion by 2050—almost 15 and 9 percent, respectively, of total investment needs of the RPDP8. The limited debt headroom is compounded by EVN’s deteriorating finances: generation costs have risen faster than inflation while tariffs were only inflation adjusted, causing recurring losses. EVN has delayed electricity payments to developers, increasing operational and financial risks for the VRE sector. High interest rates and restricted access to long-term project finance further complicate capital mobilization in emerging markets. Domestic banks, constrained by limited balance sheet sizes and limited capacity in different financial instruments, typically lack capacity to underwrite long-term project finance loans and typically require corporate guarantees, sidelining smaller developers. Currency risk adds to complexity, given the frequent local currency dominance in PPAs while international lending is in US dollars. In addition, market risk exposure is a reality, given the lack of financial instruments such as currency hedging products, partial credit guarantees, or blended finance structures. EAP’s energy transition will be expensive and capital investment intensive, requiring approximately US$9 trillion in new assets alone between 2020 and 2040. Including stranded fossil fuel assets and transmission and distribution infrastructure and distributed renewable energy upgrades, it is projected to be even more expensive. High interest rates, limited access to long-term project finance, and a lack of financial instruments threaten capital mobilization in the region. Accelerating VRE Deployment in the Focus Countries 49 4. Accelerating VRE Deployment in the Focus Countries Considering the specific challenges faced by the four focus countries, this chapter explores recommendations tailored to scaling up variable renewable energy (VRE). Key steps include updating planning, considering structural changes in power demand, developing transparent VRE procurement mechanisms, making the power system more flexible, and setting pathways for raising transition capital. The chapter also examines case studies from other countries to illustrate best practices for accelerating VRE capacity additions. The case studies presented in this report are limited to pillars 2 and 3, which form the root of the challenges faced by the focus countries—as evidenced by the discourse in the previous chapter. Table 4.1 Summary of Recommendations for Accelerating VRE Deployment Energy Security, Affordability, and Sustainability 1. National Ambition 2. Enabling Policies, 3. Infrastructure and 4. Financing and and Renewable Energy Regulatory Frameworks System Operation Investment Climate Target Planning Develop De-risk investments Invest in transmission Optimize the role comprehensive in variable renewable network upgrades, of public, private, power system energy through develop ancillary and concessional planning strategies transparency and services and capacity finance to reduce the aligned with predictability reserve markets weighted average cost structural changes in procurement with adequate of capital; employ in electrification procedures and tariff compensation for concessional capital demand and the frameworks and energy storage, for low-interest and requirements for standardize power and harmonize the long-term maturity integrating variable purchase agreement regional power trade loans; and spearhead renewable energy templates to balance framework with an the development (transmission risk allocation emphasis on alignment of voluntary and network, ancillary and boost project with grid codes. compliance carbon services, adaptation bankability. markets. and resilience measures, etc.). Note: Refer to appendix F for details on additional pathways for accelerating VRE deployment in the focus countries. Official Use Only 50 Table 4.2 Key Recommendations for Accelerating VRE Deployment in the Focus Countries Market Recommendations • Develop an ancillary services and capacity reserve market to scale up energy storage. China • Encourage cross-provincial power system planning for interregional trade. • Introduce generation flexibility through transparent economic dispatch. • Adopt large-scale transparent auctions with a predictable timetable to attract private sector investors and meet national targets. Indonesia • Focus on investment in the capacity and flexibility of transmission and distribution networks to absorb additional integration of variable renewable energy, for example, smart grids and energy storage. • Provide policy certainty by establishing a transparent and predictable tariff framework and procurement mechanism for variable renewable energy to restore market confidence. Vietnam • Invest in transmission infrastructure upgrades to improve grid integration. • Make power purchase agreements more bankable, to attract private sector investments. • Optimize the role of public and private sectors in transmission and grid infrastructure upgrades. • Reform the scope of the Energy Virtual One-Stop Shop for a streamlined permitting process. Philippines • Refine renewable energy auction design and requirements (e.g., performance bonds). • Enable a fully competitive contestable retail market by fully operationalizing the Retail Competition and Open Access framework and broadening access to direct renewable energy procurement. Pillar 1. Power market planning needs to be transparent, institutionally aligned, and adequately consider new demand drivers All East Asia and Pacific (EAP) countries should adopt a comprehensive energy-planning framework that aligns national renewable targets with broader system planning. Power sector plans must align with Nationally Determined Contributions (NDCs), energy-sector plans, and domestic climate ambitions, clarifying the power sector’s contribution to overall emission reduction targets. Governments should establish interministerial coordination platforms and shared datasets to enable coherent implementation and avoid contradictions across documents. Electrification requirements stemming from industrial decarbonization, e-mobility, digitalization, data centers, and other demand growth drivers need to be adequately incorporated in planning. Countries across EAP should undertake advanced power system modeling and demand forecasting assessments Accelerating VRE Deployment in the Focus Countries 51 that incorporate new drivers of demand to realize more accurate projections for power sector planning. Generation source planning for VRE should also consider the full potential of DRE when modeling national capacity targets and avoiding demand supply imbalances. DRE, on unused land or rooftops, offers a viable pathway for all customer segments—residential, commercial, and industrial— to secure VRE through on-site power production. On-site generation coupled with energy storage offers an opportunity to partially phase out captive generation plants. Accurate resource assessments of DRE potential are therefore critical to an optimal scale-up of VRE. Mandating solar rooftop installations on new buildings, streamlining the permitting and approval process, and enabling sales of excess power to grid can boost DRE take-up. Scaling up DRE can play an important role in increasing the take-up of VRE in remote islands across Indonesia and the Philippines. For instance, in China, the distributed generation capacity of solar PV on industrial, commercial, residential, and administrative land is estimated to be a massive 380 GW, with a generation of approximately 440 TWh annually (Wang, He, and Chen 2021). Box 4.1 Germany’s Distributed Generation Strategy for Scaling Up Renewable Energy As of April 2025, Germany’s solar capacity installations stood at 104 GW, of which 38 percent and 29 percent came from residential and commercial rooftop PV respectively, 32 percent from ground- mounted and just under 1 percent from balcony installations (Clean Energy Wire 2025a). To meet its target of 215 GW solar installations by 2030, Germany is aiming to triple annual capacity additions from 7.5 GW in 2022 to 22 GW by 2026—with half of the additions planned to come from rooftop solar PV and the remaining from ground-mounted projects—making distributed generation a core component of renewable energy scale-up (Climate Action Europe 2024). To propel the growth of distributed generation systems, the German market enables a streamlined permitting and grid connection process. This includes the removal of construction permits for rooftop PV, or system certificates for the grid connection of commercial PV systems up to 500 kW. The investment boom in rooftop solar in Germany is also attributed to feed-in tariffs and a contract for difference (CfD) scheme. New installations above 200 kW from 2026 are required to participate in a two-sided CfD scheme—enabling stability in power prices and return on investments. To maintain grid stability, the German distributed generation strategy is complemented by the expansion of consumer-owned battery storage systems (of the nearly 600,000 battery storage systems installed in 2024, roughly 580,000 were installed in homes) (Clean Energy Wire 2024). As a consequence, the 19 GWh energy storage capacity in Germany is dominated by residential systems (15.4 GWh), followed by commercial (1.4 GWh) (Strategic Energy Europe n.d.). Comprehensive sector planning requires leveraging and integrating the growth potential of distributed generation, enabled through a streamlined permitting process and a conducive investment framework, to push renewable energy penetration in the region. A harmonized approach to power system planning should encompass flexibility requirements for VRE integration. To avoid congestion and integration constraints, plans must assess investments across the VRE value chain—new generation (including distributed), fiscal needs for transmission and distribution upgrades, and targets for battery storage participation in ancillary service markets. They should also incorporate adaptation and resilience by funding climate vulnerability assessments and resilience upgrades (e.g., microgrids, distributed and off-grid generation). Off-grid solutions, which do not rely on long-distance transmission networks and are more resilient to floods, shifting rainfall, and heat waves, will be vital. Countries should adopt transparent, standardized target-setting methods and disclose underlying data and assumptions—resource mapping, cost assumptions, demand forecasts—updating them regularly and grounding them in credible economic and system planning. Official Use Only 52 Develop a comprehensive power system planning strategy aligned with climate targets and NDCs while incorporating VRE integration needs through grid upgrades, infrastructure resilience, and electrification demands from various growth drivers like industrial decarbonization and data centers. Pillar 1. Market-specific Recommendations In Indonesia, institutional reforms must align utility-level planning with national transition goals, given governance fragmentation. The government could ensure that the policies and targets of the state electric utility company (Perusahaan Listrik Negara, PLN) align with national objectives by embedding clear transition commitments in the Electricity Supply Business Plan (Rencana Usaha Penyediaan Tenaga Listrik, RUPTL) and PLN’s corporate strategy, making PLN accountable for sectorwide outcomes, not just projects. To mitigate conflicts of interest in planning, procurement, and operations, it is important to separate system planning, generation procurement, and system operation from PLN’s other activities—initially by ring-fencing these functions within PLN, with a potential longer-term shift to an independent state-owned entity. Another priority is to strengthen interagency coordination via a dedicated interministerial energy committee (Ministry of Energy and Mineral Resources, Ministry of State-owned Enterprises, Ministry of Finance) to align sectoral, climate, and financial policies and ensure planning and investment decisions support a cohesive long-term strategy, improving accountability and reducing fragmentation. For Vietnam, timely and well-coordinated finalization of the Revised Power Development Plan 8 (RPDP8) is a critical priority. As the sector’s blueprint, it will clarify state-owned enterprises’ and the private sector’s roles and their investment needs, and provide analytical guidance on project schedules and milestones to steer investment, planning, and regulatory changes. Any delay in approval or implementation risks stalling pipelines, missing time-sensitive windows, and undermining clean energy targets. Vietnam should complement RPDP8 with a detailed investment plan: nearly US$135 billion in 2026–30 and almost US$700 billion in 2031–50. The plan should specify priority projects, timelines, and funding sources—including public, private, and concessional finance—to improve bankability, accelerate deployment, and guide the roadmap for required regulatory and policy reforms. Pillar 2. De-risk investments through predictable and transparent tariff frameworks, procurement mechanisms, balanced risk allocation in power purchase agreements (PPAs), and streamlined permitting processes Markets must boost investor confidence through an effective regulatory framework that provides clarity and predictability through transparent tariff setting and well-structured procurement strategies. Procurement frameworks should be tailored to market conditions, aligned with grid and long-term energy planning, and provide a predictable project pipeline that sends strong signals to developers, financiers, and equipment suppliers. In early-stage markets with low VRE deployment, clear, fixed tariffs (e.g., feed-in tariffs [FiTs]) can catalyze investment by providing transparent, visible revenue streams. As markets mature, countries should shift to regular, competitive auctions to improve cost efficiency and enable market-led price discovery. Successful auction systems require unambiguous details on schedules, volumes (aligned with long-term transition and climate targets), timelines, and investor/developer selection criteria, along with clear tariff-setting methodologies, indexation to hedge inflation and currency risks, and stable long-term policy signals. These market-led mechanisms must be tailored to regional and domestic contexts to reduce costs and enhance competition. Global experience shows well-structured auctions lower renewable costs and reduce investor uncertainty (IEA 2023b). In India, solar tariffs fell by over 80 percent from Rs 12.16/kWh (14.2 US cents/kWh) Accelerating VRE Deployment in the Focus Countries 53 in the first auction (CEEW 2016) to Rs 2.15/kWh (2.5 US cents/kWh) in recent rounds (Mercom India 2024), driven by transparent auctions and clear PPA frameworks. The Malaysia auction case study (box 4.2) illustrates the role of robust auction and regulatory design in the region. Countries should focus on standardizing PPA terms, including clear provisions on risk allocation, such as curtailment compensation, force majeure, payment securities, and government-backed guarantees. Balanced risk allocation in PPAs can make projects more bankable and make them more attractive to developers, investors, and creditors (through access to low-interest rate capital), and boost developers’ and financiers’ confidence. Government-backed guarantees and credit enhancements can further invigorate confidence in markets. EAP countries should establish clear regulations to ensure transparent tariff setting and procurement. As markets mature, it is possible to shift from fixed tariffs (e.g., FiTs) to competitive auctions, and standardize PPA terms—aligned with international standards—to balance risk, enhance bankability, and attract international investment. Pillar 2. Market-specific Recommendations Indonesia should improve the regulatory climate for VRE by increasing procurement visibility and strengthening its auction framework, enabling investors to plan and sustaining regular development and investment. Adhering to auction timelines is critical to avoid eroding investor confidence and depressing participation. Credibility also requires transparent communication of milestones and guidelines—prequalification, bid evaluation, technical assessments, and tariff negotiations—and independent oversight of the auction process. Local content rules should be phased to balance supply-chain development and affordability: allow initial waivers or lower thresholds where domestic manufacturing is weak, then tighten requirements as industry capacity matures, supported by incentives for technology transfer and workforce training. Regulatory reform is essential to legally permit independent power producers (IPPs) to sell directly to corporate buyers via a standardized, streamlined corporate power purchase agreement (CPPA) process, reducing permitting complexity. In parallel, power-wheeling regulations should allow IPPs to use PLN’s network under clear wheeling charges and grid-access rules. A robust CPPA framework would unlock private VRE investment while keeping residential retail tariffs unaffected. Indonesia must make its procurement transparent, scale up auction volumes, and ensure auctions are held and completed timely. Growth of private investment would require addressing local content requirements in phases and enabling IPPs to sign CPPAs. Vietnam should prioritize a robust competitive-bidding framework tailored to its legal, institutional, and market context. It must clarify project eligibility, auction timelines, grid-connection responsibilities, and stakeholder roles (including EVN), and adopt transparent bidding with objective eligibility and award criteria. Minimizing complexity in initial rounds will attract interest and efficiently allocate capacity. Vietnam should also provide long-term auction schedules so investors can complete predevelopment and pre-bid work— especially for offshore wind, a focus of Vietnam’s RPDP8. The Ministry of Industry and Trade (MOIT) must urgently finalize the approval of tariff brackets for competitive bidding across all renewables. Ceiling prices reflecting current technology costs and enabling reasonable returns for developers must be set in a timely manner and updated yearly, with their validity potentially extended beyond the currently planned annual time frame. Official Use Only 54 To preserve investor confidence, eligibility criteria for tariff incentives must be clearly communicated and consistently applied through the project life. For retroactive FiT reviews, a structured, transparent resolution mechanism—grounded in Resolution 233/NQ-CP—should distinguish administrative ambiguity from verifiable noncompliance; where disputes arise, independent case-by-case assessments can support equitable outcomes and limit unintended financial impacts. Going forward, procurement rules should embed clear, time-bound eligibility in legislation, aligning regulatory updates with project timelines. The MOIT should consider reviewing existing PPA templates and ensure a more equitable risk allocation— especially to attract the foreign capital required in the case of offshore wind development. Key clauses of concern (e.g., termination, arbitration, deemed power output, currency indexation, and lender step-in rights) should be revisited to make projects more bankable and boost investors’ confidence. Vietnam should urgently develop a robust competitive bidding framework that clarifies project eligibility and auction timelines, while minimizing complexities in the selection process. The MOIT must urgently finalize tariff brackets and review existing PPA templates for their suitability to increase project bankability and investor confidence. In the Philippines, auction design should be refined to boost developer and investor interest. Performance bond requirements need to be particularly reviewed—especially for small developers—to broaden participation and avoid unsubscribed capacity. The Department of Energy should publish a clear Green Energy Auction Program (GEAP) timetable with defined capacity allocations to improve competition and investor interest. The suitability of the current PPA and Renewable Energy Payment Agreement template should be reviewed, especially in the context of offshore wind projects. With offshore wind bidding planned for Q3 2025, the Energy Regulatory Commission (ERC) should address template shortcomings—curtailment, lender step-in rights, and termination—to attract a wider pool of investors and financing for capital-intensive projects. Box 4.2 Brazil’s Auction System for VRE Scale-up Brazil’s energy auction system has been a cornerstone of its variable renewable (VRE) expansion, enabling the country to rapidly scale up wind and solar power while maintaining competitive pricing and attracting private investment. Brazil, with vast hydro resources with large reservoirs, has had a historical hydropower dominance in its power generation mix, but was prompted to explore additional energy sources by the severe droughts in the early 2000s, leading next to a significant power sector reform in 2004 for prioritizing energy security and resource adequacy in investment, ensuring fair and cost-reflective tariffs, reintroducing central planning to manage demand growth, and establishing a stable regulatory framework (Tolmasquim et al. 2021). Central to this reform was the introduction of energy auctions, which have since been instrumental in catalyzing private investment by pairing long-term power purchase agreements (PPAs) with stable regulation and targeted incentives. Since auctions began in 2007, Brazil has contracted over 33 GW of renewables, driving an eightfold rise in annual renewable generation (NetZero Pathfinders by BloombergNEF n.d.). By 2023, wind and solar alone accounted for 29.4 and 20.7 percent of Brazil’s installed capacity and generation mix, respectively (EPE 2024). Ca Ave 200 0.10 0.60 100 900 0.00 0 800 0.50 0.478 Average Bid Price (MYR/kWh) LSS1 LSS2 LSS3 LSS4 700 0.412 Capacity Awarded (MW) 0.40 600 500 0.30 400 0.274 0.206 0.20 Accelerating VRE Deployment in the Focus Countries 300 55 200 0.10 100 0.00 0 LSS1 LSS2 LSS3 LSS4 Figure B4.2.1 Figure B4.2.1 Brazil’s Installed Brazil’s Capacity, Installed Capacity, 2000–23 2000–23 250 200 150 GW 100 Figure B4.2.1 Brazil’s Installed Capacity, 2000–23 50 250 0 200020012002200320042005200620072008200920102011201220132014201520162017201820192020202120222023 200 Coal Gas Oil Nuclear Others Bio Hydro Solar Wind Source: IRENA. 150 Note: GW = gigawatt. GW Price Trend of Solar PV in the Energy Auction in Regulated Electricity Market 100 A notable trend 120 in Brazil’s energy auctions is the substantial reduction in prices over time. For example, 103.0 Average Price (US$/MWh) the first technology-specific 100 88.0 onshore 84.3 wind auction in 2019 awarded contracts at US$84.8/megawatt-hour 50 78.3 (MWh). However, 80 by 2022, prices had dropped to US$33.1/MWh (BNEF 2024b). The price of solar has fallen, likewise—declining 60 from US$103/MWh 44.3 in 2013 to US$32.3/MWh in 2022 (ABSOLAR 2024). Solar 0 and wind energy 40 are becoming increasingly affordable in Brazil, making 35.2 them 30.9 more 37.2 competitive with 32.3 200020012002200320042005200620072008200920102011201220132014201520162017201820192020202120222023 25.9 20.3 23.8 traditional energy 20 sources. 17.6 Coal Gas Oil Nuclear Others Bio Hydro Solar Wind 0 PE Auction LER 2014 1st LER B4.2.2 Figure 2015 2nd LER LEN 2015 Solar 2017 PV A-4 LEN Auction A-4 2018 Price LEN A-6 LEN 2019 A-3 LEN 2021 Trends A-4 LEN 2021 in Brazil A-4 2021 LEN A-5 2021 LEN A-4 2022 LEN A-5 2022 2013 Price Trend of Solar PV in the Energy Auction in Regulated Electricity Market 120 103.0 Average Price (US$/MWh) 100 88.0 84.3 78.3 80 60 44.3 35.2 37.2 30.9 32.3 40 23.8 25.9 17.6 20.3 20 0 PE LER 1st LER 2nd LER LEN A-4 LEN A-4 LEN A-6 LEN A-3 LEN A-4 LEN A-4 LEN A-5 LEN A-4 LEN A-5 Auction 2014 2015 2015 2017 2018 2019 2021 2021 2021 2021 2022 2022 2013 Source: Chamber of Electric Energy Trading/ABSOLAR. Note: LEN = New Energy Auction; LER = Reserve Energy Auction; MWh = megawatt-hour; PE = Pernambuco state. Brazil’s auction model succeeds due to a robust regulatory framework, clear institutional roles, and transparent, predictable rounds—typically annual or semiannual—all of which send strong market signals. Integration with centralized energy planning further strengthens the system: long-term plans provide a roadmap for capacity expansion, reducing information asymmetry and investment risk. Official Use Only 56 Execution rests on tight institutional coordination. The Ministry of Mines and Energy sets auction guidelines, schedules, bidding rules, and selection criteria. The Energy Research Office (EPE) conducts technical prequalification—reviewing project datasheets, land rights, and environmental permits— and issues a technical note that informs price caps and the maximum energy each project can sell. The Brazilian Electricity Regulatory Agency (ANEEL) runs the auction process, assessing bidders’ legal, financial, and technical qualifications, with support from the Chamber of Electric Energy Trading, and oversees project execution (Tolmasquim et al. 2021). Another key factor in Brazil’s success is the use of long-term PPAs, usually lasting 15 to 20 years. These agreements reduce revenue uncertainty and improve project bankability. The contracts often link to domestic price inflation, which lowers risk and ensures financial stability for developers. Private sector investment also gets support from long-term financing in local currency from Brazil’s development bank (BNDES). This boosts investor confidence and helps the growth of local supply chains. Auction participants can obtain financing from international sources or BNDES. However, those who choose BNDES funding must source components from accredited local manufacturers. This policy effectively increases demand for domestically produced equipment, such as panels, inverters, and trackers, which further promotes the development of a local supply chain (IRENA 2024b). Box 4.3 Large-Scale Solar (LSS) Auction in Malaysia Malaysia’s Large-Scale Solar (LSS) program, launched in 2016 and administered by the Energy Commission of Malaysia (EC), aims to accelerate solar deployment through competitive auctions. Designed to encourage transparent bidding, it awards 21-year power purchase agreement to developers for solar power projects with 1–500 MW of capacity, incentivizing private sector participation in utility- scale solar projects. The auctions are conducted regularly. The EC announces a preliminary schedule for the annual tender. LSS 1, LSS 2, LSS 3, and LSS 4 were held in 2016, 2017, 2019, and 2020, respectively, successfully procuring 2.3 GW of solar capacity for the country (IRENA 2022b). LSS 5 targets an additional 2,000 MW, nearly doubling the program’s cumulative capacity. Figure B4.2.1 Malaysia: Average Bid Price and Capacity Awarded for LSS1 and LSS4 0.60 900 800 0.50 0.478 Average Bid Price (MYR/kWh) 700 0.412 Capacity Awarded (MW) 0.40 600 500 0.30 400 0.274 0.206 0.20 300 200 0.10 100 0.00 0 LSS1 LSS2 LSS3 LSS4 Source: IRENA. Note: kWh = kilowatt-hour; LSS = Large-Scale Solar program; MW = megawatt; MYR = Malaysian ringgit. Figure B4.2.1 Brazil’s Installed Capacity, 2000–23 250 Accelerating VRE Deployment in the Focus Countries 57 The LSS program has successfully achieved cost reduction. Since its inception, solar tariffs have declined significantly, with LSS 4 (2021) awarding projects at an average bidding price of RM 0.2065/kWh (US$0.0501/kWh)—a 56.8 percent reduction from LSS 1 (2016). The LSS auctions use clear registration and qualification steps to ensure transparency and efficiency. Bidders first pass a request for quotation (RFQ), then shortlisted firms submit full proposals at the request for proposal (RFP) stage. Standardized guidelines and documents, plus preidentified grid connection points developed with Tenaga Nasional Berhad, reduce uncertainty and streamline execution. Developers bear connection costs; projects above 30 MW connect to the transmission grid, while smaller projects connect to the distribution network. Ownership requirements have evolved over the auction rounds. Initially, foreign ownership was capped at 49 percent, but only wholly Malaysian-owned companies or locally listed firms could participate in later rounds, to LSS 4. LSS 5 has reintroduced the 49 percent foreign ownership allowance, broadening investor participation. Project selection applies a multicriteria framework—grid-connection feasibility, land-use efficiency, local content, and socioeconomic benefits—with added incentives for projects in less-developed regions to promote equitable growth. Bankability is strengthened by financially stable offtakers, primarily Tenaga Nasional Berhad. The LSS follows a build-own-operate model with take-and-pay payments, supporting revenue stability and grid reliability. A predictable auction schedule makes the domestic supply chain more efficient by providing future demand visibility, allowing engineering, procurement, and construction contractors to optimize production, inventory, and workforce planning. The LSS program has also encouraged local firms like Solarvest to expand, reducing balance-of-system costs through localized supply chains. EAP countries should evaluate the feasibility of establishing a one-stop shop to fast-track VRE permitting— a single contact point that coordinates approvals across agencies. A centralized permitting body should also identify priority zones with available grid capacity to accelerate projects. The Philippines should expand Department of Energy’s 2019 Energy Virtual One-Stop Shop (EVOSS) into a true single permitting hub, acting as the liaison among local government units and agencies (e.g., the Department of Agrarian Reform) to ease land acquisition, cut costs, streamline communication, and shorten timelines. Global experience shows coordinated licensing and permitting improve developer execution and support sector success. Box 4.4 Streamlining Offshore Wind Permitting Through a One-Stop-Shop in Denmark Denmark’s one-stop shop has been pivotal to its rise as a leading offshore wind market. It streamlines the complex permitting process by replacing multiple agency interactions and individual permits with a single, coordinated channel. By aligning licensing and permit requirements, the system reduces regulatory and delay risks, giving developers and investors confidence to build offshore wind capacity. The Danish Energy Agency (DEA) acts as a single primary contact channel for a transparent and centralized permitting process. Within the DEA, every project is assigned a designated case officer and project team to assist in operational matters. The DEA coordinates with the relevant regulatory authorities, which provide inputs to the DEA on their respective regulations. Official Use Only 58 Figure B4.3.1 Danish Energy Agency and Key Entities Through this cross-functional engagement, the DEA coordinates and grants licenses for: • Preliminary investigation—the project developer submits a project plan—for the DEA to seek approval from relevant authorities, after which preliminary studies can commence. 0.60 900 • Construction of an offshore wind farm—after preliminary studies and collecting site information, 800a relevant authorities are provided with a detailed project application for their approval for 0.50 0.478 Average Bid Price (MYR/kWh) construction license. 700 0.412 Capacity Awarded (MW) • Electricity production—the developer must comply with the requirements of the construction license 0.40 600 and provide detailed documentation. The DEA and relevant authorities grant the electricity production 500 0.30 license upon approval. 400 0.274 0.206 0.20 300 Regulators should focus on easing land acquisition procedures to expedite VRE project development. 200 Transparency in the leasing or land acquisition processes provides predictability to investors and project 0.10 developers. Integrating land acquisition with a one-stop shop—and eliminating multilayered negotiations 100with individual 0.00 landowners—will streamline project development. 0 LSS1 LSS2 LSS3 LSS4 Box 4.5 Leveraging Government-Owned Land to Expedite Large-Scale Solar Projects in India India stands out as a regional peer for its supportive policy landscape for land acquisition for large-scale solar. In 2014, the Ministry of New and Renewable Energy launched the “Development of Solar Parks and Ultra Mega Solar Power Projects” to establish 25 projects totaling 20 GW in five years (MNRE 2025). The scheme was later revised to 40 GW with a time frame to March 2026. The central government supports states in setting up designated solar parks. To ease land acquisition, the scheme provides developers land with requisite clearances, transmission infrastructure, road connectivity, and telecom—minimizing risk and speeding grid connections for a “plug-and-play” business model. Under the scheme, host state governments identify park land, prioritizing government-owned waste/ Figure B4.2.1 Brazil’s Installed Capacity, 2000–23 nonagricultural sites and minimizing private acquisition. An implementing agency acquires land and 250 secures clearances. 200 150 GW 100 Accelerating VRE Deployment in the Focus Countries 59 The scheme has enabled large-scale solar projects. As of June 2023, under the “Development of Solar Parks and Ultra Mega Solar Power Projects” scheme, the government has sanctioned 38 GW of capacity across 50 projects (Press Information Bureau 2023). For example, the developer for the 750 MW Rewa Solar Park avoided multiagency engagement. About 80 percent of land was state-owned contiguous barren land (Vyas, Adhwaryu, and Bhaskar 2022); the remaining 20 percent was acquired from private owners under “mutual consent” (India’s Department of Economic Affairs 2025) at a premium over market price to ensure fairness and reduce disputes. Pillar 3. Invest in transmission infrastructure, introduce market participation frameworks for energy storage, and harmonize grid codes for regional trade EAP countries should upgrade grid infrastructure in sync with VRE capacity additions. Grid and transmission infrastructure will have to be upgraded faster to streamline VRE integration. Independent power transmission and build-operate-transfer systems should be leveraged to spearhead private sector participation. Battery storage for ancillary and grid-flexibility services should be prioritized immediately. With infrastructure build-out lagging VRE additions—and storage integration raising system costs—enabling regulatory frameworks are critical to incentivize deployment, including capacity payments and participation rights for storage assets. Grid-balancing services (frequency regulation, voltage control) must be properly valued to attract storage participation and enable VRE integration. Widespread deployment of battery storage systems is essential for all markets but particularly crucial for countries (e.g., China) with a high share of VRE penetration. With VRE capacity exceeding 1,400 GW in China, battery storage systems are critical components to manage generation variability, balance power supply and demand, and cost-effectively maintain power system reliability. At the same time, in markets like Vietnam, Philippines, and Indonesia, where VRE capacity additions are bound to accelerate, investments in battery storage systems must keep pace and follow closely with increases in VRE generation. This deployment of battery storage systems must be addressed via installations in the distribution network (close to load centers) as well as colocation with VRE resources. Regional power trade frameworks should be harmonized—starting with grid code alignment—to strengthen energy security. Harmonizing grid codes across the Greater Mekong Subregion and the Association of Southeast Asian Nations (ASEAN) Power Grid will set minimum technical, design, and operational standards for reliable interconnected operation; at a minimum, alignment should cover cross-border interconnectors. A feasibility study for HVDC interconnections should also be undertaken across borders with a mismatch in grid codes. Developing a methodology to support transparent import price frameworks and common wheeling charges for multilateral power trading will provide incentives to build infrastructure. Countries engaged in power wheeling should be adequately compensated for future infrastructure development. The wheeling charge must be stable and provide predictable price signals to investors engaged in transmission network development. Regional institutions like ASEAN play a critical role and must continue to lead the regional energy transition forward. The disparities in power sector market maturities requires regional institutions to foster cooperation among member states on regional power trade. The region could benefit from coordinating infrastructure planning—for both generation and network assets—aligning regulatory frameworks, promoting data sharing, Official Use Only 60 and balancing power supply and demand. To enable multilateral power trading, it is important to employ a methodology to support transparent import price frameworks and common wheeling charges with predictable price signals, adequately compensating for future infrastructure development. This requires consensus amongst ASEAN member states and consequently the significant support required from ASEAN needs to be emphasized. EAP countries would do well to develop a comprehensive grid upgrade plan aligned with VRE additions and assess leveraging independent power transmission and build-operate-transfer to attract private participation. They could also establish regulatory frameworks that incentivize energy storage deployment and ancillary services to ensure grid resilience and flexibility. Grid codes must be harmonized for regional power trade, alongside assessments for HVDC interconnections. Box 4.6 Nord Pool—Using Regional Power Trade for Energy Security Nord Pool’s groundwork was laid by Norway’s 1991 market deregulation and the creation of Statnett Marked, which was replaced in 1996 by Nord Pool—jointly established by the Norwegian and Swedish transmission system operators. It has since expanded to Denmark, Finland, the Baltics, the United Kingdom, and Central Western Europe. As the world’s first multinational power exchange, Nord Pool runs centralized day-ahead and intraday markets, enabling about 400 members across 20 countries to trade. Its principle-based regulation (IEA 2019) allows dynamic adaptation to changing conditions. Nord Pool’s multinational power trade network diversifies supply and reduces risk. Norway (89 percent) and Sweden (40 percent) rely heavily on hydro; in normal rain and snow years, hydro meets most demand, while in dry years imports from the region fill gaps. Seasonal diversity also improves efficiency—Nordic heating peaks in winter, southern cooling in summer. In 2022, 1,077 TWh was traded (up 12 percent from 2021), including 696 TWh in the Nordic and Baltic day-ahead markets (Nord Pool 2023). During the 2022 energy crisis, average wholesale prices reached €330/MWh in Germany and exceeded €320/MWh in France, while Nord Pool prices hovered around €150/MWh (they rose year-on-year due to low Nordic hydro and higher cross-zonal demand but remained below European averages) (IEA 2023c). Nord Pool’s example illustrates how regional cooperation and trade bolster energy security, lower costs, and support variable renewable energy integration. Pillar 3. Market-specific Recommendations China could focus on developing an ancillary services and capacity reserve market that adequately compensates energy storage services to support power system reliability. A clear, transparent revenue regime is essential to attract private participation. Cross-provincial planning for inter-regional trade should move VRE from resource-rich regions to demand centers. Given China’s vast geography and differing provincial load curves, interprovincial trading can enable imports and reduce the need for new coal plants. Because VRE can be built faster than transmission, collaborative planning is critical to optimize network capacity and facilitate power trading. China could prioritize the development of an ancillary services and capacity reserve market and promote interregional power trade. Accelerating VRE Deployment in the Focus Countries 61 Indonesia needs to accelerate investment in the capacity and flexibility of transmission and distribution. Priorities include strengthening interconnections between island systems to better balance supply and demand, facilitating the transfer surplus VRE from resource-rich islands to demand centers, and addressing the challenges of localized over- and undersupply. Advanced grid technologies—smart grids and energy storage— may be deployed to manage renewable variability and ensure reliable supply across diverse geographies. These upgrades need to be anchored in pricing and regulatory frameworks that properly value storage and ancillary services to attract private participation and enhance system flexibility. Vietnam must upgrade transmission in parallel with VRE additions. Immediate grid upgrades are needed to minimize the risk of VRE curtailment. Planning should assess co-locating VRE with load centers and upgrading networks to connect resource-rich regions to demand. An ancillary-services market should be designed and developed. At the same time, clarifications are needed for the role and long-term orientation of storage and flexible power to unlock investment and enhance system flexibility for further VRE integration. The Philippines should optimize public and private roles in transmission and grid upgrades, and clear bottlenecks by resolving right of way (ROW) issues, including revising compensation. The ERC should proactively expedite pending National Grid Corporation of the Philippines transmission applications. It is important to prioritize TransCo-led public-private partnerships for upgrades outside the Transmission Development Plan to strengthen the grid for VRE. With the executive order enabling TransCo to step up its role in constructing grid infrastructure still pending, the Office of the President must expedite its issuance (Manila Bulletin 2024). The Philippines must balance public and private sector investments for timely network upgrades and streamline issues such as ROW, which have delayed upgrades in the past. Box 4.7 Catalyzing Private Investments in Transmission Infrastructure in Brazil Among emerging economies, Brazil has mobilized private capital for grid infrastructure through the independent power transmission model. Planning is centralized, while implementation is decentralized. The Brazilian regulatory agency, ANEEL, runs tenders open to public and private firms, anchored by 30- year build-own-operate-transfer contracts with annual payments upon the commercial operation date. Bidding is based on the lowest annual revenue to the independent power transmission project, subject to an ANEEL-set cap. To participate in the tender, bidders must meet technical and financial conditions (e.g., subcontractor contracts, liquidity, tax compliance). Winners are chosen via reverse bidding with construction deadlines and service rules; on-time delivery is incentivized and delays penalized. This model reduces investor risk, encourages private participation, and lays the groundwork for a more competitive power network. This model resulted in the award of 50 tenders between 1999 and 2020 for the construction and operation of 96,000 kilometers of transmission lines by the private sector (OECD 2021). Since 1999, Brazil has received over US$38 billion in private capital—mainly as long-term concessions—expanding transmission infrastructure. This competitive process has also helped reduce transmission costs: the winning bids between 1999 and 2020 were on average 25.8 percent lower than the costs forecasted by ANEEL. Official Use Only 62 Pillar 4. Undertake comprehensive investment planning and syndicate capital requirements through all domestic and international sources Funding the capital-intensive energy transition requires a strategic blend of public, private, and concessional resources—including carbon markets—to minimize the levelized cost of energy. A strategic realignment of the domestic banking sector’s lending priorities is essential. Regulatory incentives should be introduced to encourage banks to allocate a greater proportion of their credit to VRE and infrastructure projects. Establishing a long-term refinancing facility, possibly supported by MDBs, would also enable domestic banks to extend project financing without breaching regulatory short-term funding limits. Nascent markets would get a boost from efforts to strengthen the capacity of domestic financial institutions to provide nonrecourse project financing and refinancing options by offering capacity building programs on project appraisal, risk assessment, loan structuring, and by strengthening capital market instruments, including project bond refinancing structures. Clear, credible investment plans—aligned with national power strategies and clean energy targets— should map the scale and timing of needs across generation, grids, and enabling technologies, and outline how to mobilize public and private capital. Scenario-based approaches and syndication models (multilateral development banks, commercial lenders, institutional investors) can help crowd in finance and lower the weighted average cost of capital (WACC). Plans should account for higher global interest rates and include contingencies for capital-intensive segments (e.g., offshore wind). Governments should actively explore alternative financing avenues, including asset divestments and the securitization of existing operational assets. These strategies can generate additional fiscal space for new investments, thereby supporting the ambitious goals set forth in the national plans. Concessional finance must be mobilized at scale and strategically deployed over the next decade. Concessional finance is essential for supporting early stage investment in the derisking of new technologies, enabling grid upgrades and interconnections considered public strategic assets, ensuring system stability though ancillary services, including energy storage solutions that are necessary to integrate VRE but may not be immediately financially viable. Scaling up concessional financing is therefore essential to address affordability constraints and enable countries in the EAP region to pursue ambitious VRE targets without compromising energy access or economic competitiveness. Additionally, VRE investments are capital-intensive, requiring high up-front investment with payback realized over time through an absence of fuel-related expenditures. As energy systems become more capital-intensive, the cost and availability of capital become critical determinants of both the pace and affordability of the transition. With a lack of domestic financial market capacity for long- term financing, a successful energy transition hinges on alignment between the financing tenor and lifespan of VRE assets. Concessional capital, through low-interest rate loans and long-term maturity, grants, and guarantees, can significantly lower the weighted average cost of capital (WACC) for VRE projects. This improves risk-adjusted returns, enhances bankability, and facilitates the crowding-in of private capital. Concessional finance also plays a catalytic role in de-risking investment environments, particularly in markets where regulatory uncertainty, currency volatility, or offtaker risks deter commercial financing, and in the case of new technologies. Accelerating VRE Deployment in the Focus Countries 63 To access international financing, governments, in collaboration with MDBs and DFIs, should prioritize the development of currency risk mitigation tools. FX hedging products and risk-sharing facilities will be instrumental in providing protection against fluctuations between local currency denominated revenue and foreign currency denominated loans. Expanding guarantee mechanisms can significantly improve project bankability. Credit enhancement products, partial risk guarantees, and performance bond guarantees can lower financing costs, not only for smaller developers but also for off-takers with weaker credit profiles. These measures help crowd in private lenders and institutional investors who otherwise may be deterred by perceived risks. Using blended financing structures, combining private and concessional finance to create such products and de-risk private investment, can catalyze investment at scale. EAP countries could tap into programs such as the World Bank’s Sustainable Renewables Risk Mitigation Initiative (SRMI), which mitigates risk for VRE projects through upstream and downstream technical assistance, targeted funding for public sector investments (e.g. battery storage, grid reinforcement) and risk mitigation instruments like guarantees and political risk insurance. As of January 2023, 19 SRMI projects had been approved—$3.9 billion World Bank financing blended with $0.675 billion climate finance. Voluntary carbon markets (VCMs) should be accessed while developing long-term compliance markets tailored to EAP. Carbon markets provide grant-like funding tied to verified emission reductions without fiscal liabilities. As Vietnam and the Philippines advance compliance frameworks, private actors pursuing net zero and carbon neutrality are increasingly using VCMs; VRE developers can improve project financials. Carbon pricing both cuts greenhouse gases and adds revenue (World Bank 2024b); worldwide carbon pricing reached US$104 billion in 2023 (World Bank 2024c). Clear, credible, and predictable carbon pricing signals serve to provide developers and investors’ confidence to plan long-term power sector projects. Carbon pricing instruments must consider the regional context: growing electricity demand, energy affordability, high costs of capital, and the volatility of international energy prices (for import dependent economies). Instruments must mitigate emissions while minimizing additional economic burdens. To accurately quantify emissions reductions and secure carbon finance, countries must develop rigorous and accurate baseline conditions. Developing an internationally recognized monitoring, reporting, and verification (MRV) framework, in line with global standards, will enhance credibility and generate higher quality Renewable Energy Certificates (RECs) that can fetch higher market prices as well as support international exports. REC prices upwards of US$30/ton can help fund large capital expenditure and transmission for VRE. Carbon markets can also finance transmission upgrades to de-risk network investment. Governments can restore investor confidence in the corporate bond market as a complementary source of long-term capital by strengthening disclosure, regulatory oversight, and legal clarity around refinancing. Green bond issuance can be incentivized through tax incentives, reduced regulatory capital requirements, and the establishment of green bond frameworks aligned with international standards. 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Washington, DC: World Bank. World Bank. 2022a. Vietnam Country Climate and Development Report. Washington, DC: World Bank. World Bank. 2022b. Offshore Wind Roadmap for the Philippines. Washington, DC: World Bank. World Bank. 2023a. Indonesia Country Climate and Development Report. Washington, DC: World Bank. World Bank. 2023b. “Accelerating Sustainable Energy Transition Multi-Phase Programmatic Approach (P181555).” Project Information Document, World Bank, Washington, DC. http://documents.worldbank.org/curated/en/099121923135524586. World Bank. 2024a. “International Coal Price: Higher-for-Longer.” https://blogs.worldbank.org/en/opendata/international-coal-price--higher-for-longer. World Bank. 2024b. Scaling Climate Action by Lowering Emissions: Annual Report 2024. Washington, DC: World Bank. https://thedocs.worldbank.org/en/doc/0302ae6592e75d165e833c6601c7e6f4-0020072024/original/SCALE- Annual-Report-2024-Web-Final.pdf. World Bank. 2024c. “Carbon Pricing in the Power Sector-Role and Design for Transitioning Towards Net-Zero Carbon Development.” https://blogs.worldbank.org/en/climatechange/carbon-pricing-in-the-power-sector---role-and-design-for-transit. World Bank. 2025. Green Horizon: East Asia’s Sustainable Energy Future. Washington, DC: World Bank. https://documents1.worldbank.org/curated/en/099062025065033035/pdf/P176829-00a131a7-fd03-4852- 8163-a528f13dfb9c.pdf. World Bank. N.d. “GDP per Capita (Constant 2015 US$).” https://data.worldbank.org/indicator/NY.GDP.PCAP.KD. WWF (World Wide Fund for Nature), Philippines. 2023. “Monitoring Renewable Energy Implementation in the Philippines (MoRE) Project.” Policy Brief. https://wwfph.awsassets.panda.org/downloads/monitoring-renewable-energy-implementation-in-the- philippines-project-policy-brief.pdf. Zhang, G., M. Fan, and C. Lv. 2023. “Mechanism Design of China Ancillary Service Market Considering Provincial and Inter-Provincial Market Characteristics. SHS Web of Conferences 163: 02037. https://doi.org/10.1051/shsconf/202316302037.   Appendix A. Other EAP Energy Indicators 71 Appendix A. Other EAP Energy Indicators The East Asia and Pacific (EAP) region is the largest contributor to the global increase of greenhouse gas (GHG) emissions. EAP accounted for roughly 42 percent of the 51.7 gigatons of carbon dioxide equivalent (GtCO2e) global emissions in 2023. Between 1990 and 2023, global GHG emissions increased by 61 percent. The largest increase in emissions was contributed by EAP, with emissions nearly tripling from 7.5 GtCO2e in 1990 to nearly 21.9 GtCO2e in 2023. Within the region, four focus countries, namely China, Indonesia, Vietnam, and the Philippines, underline this growth, with their share of EAP emissions rising from nearly 60 percent in 1990 to roughly 82 percent in 2023. Figure A.1 Total GHG Emissions by Region ()(&NJTTJPOTCZ3FHJPO   4IBSFPG5PUBM  4VC4BIBSBO"GSJDB   -BUJO"NFSJDB BOE$B SJCCFBO  .JEEMF &BTUBOE/PSUI"GSJDB  (U$0 F  4PVUI "TJB  /PSU I"NFSJDB 3FHJPO   &VSPQFBOE$FOUSBM"TJB  &BTU"TJBBOE1BDJGJD                                                                                                          Source: EDGAR. Note: GHG = greenhouse gas; GtCO2e = gigatons of carbon dioxide equivalent. Rising power demand in EAP is fueling this rise of GHG emissions in the region. Increased electrification of economies within the region and their role in supporting global supply chains has resulted in the power sector emissions increasing by nearly 500 percent between 1990 and 2023. The power sector’s share of total EAP emissions has climbed from just under 19 percent in 1990 to over 38 percent in 2023. The focus countries are behind this rise, with their power sectors collectively responsible for nearly 85 percent or 7.1 Gt CO2e of EAP’s power sector’s 8.3 Gt CO2e emissions in 2023. Power sector GHG emissions are closely followed by emissions from industry—which accounts for roughly 28 percent of EAP emissions. Growth in demand in the power sector has been underpinned by the recent and rapid industrialization of the focus countries in recent decades, with sectors such as general manufacturing, steel and iron, cement and chemicals, and so on, propelling their economic growth. A heavy reliance on fossil fuels like coal, to drive these energy-intensive sectors has pushed industry emissions to new highs. Official Use Only 72 Figure A.2 EAP—GHG Emissions by Sector, 1990–2023 Source: EDGAR. Note: EAP = East Asia and Pacific; GHG = greenhouse gas; GtCO2e = gigatons of carbon dioxide equivalent. EAP’s power sector accounts for a much larger share of total GHG emissions relative to other regions, with the sector’s emissions growth rate outpacing other counterparts. While EAP’s power sector accounts for a 38 percent share of total emissions, in its regional counterpart, South Asia, the sectoral share stands at 30 percent. Sectoral emissions in EAP increased at an average annual growth rate (AAGR) of 5.77 percent between 1990 and 2023, on par with South Asia and in sharp contrast to the negative AAGR rates observed in Europe, Central Asia, and North America during that time. Zooming in on the focus countries, the emissions growth rate of the power sector is more pronounced—Vietnam: 13.03 percent, Indonesia: 8.19 percent, China: 7.59 percent, and the Philippines: 7.51 percent. Figure A.3 Power Sector Emissions AAGR and Share of Total Emissions Share of Power Sector in Total Average Annual Power Sector GHG Emissions Growth Emissions (2023) (1990-2023) 30.44% Vietnam 22.68% Indonesia 41.02% China 33.97% Phili ppi nes 29.86% South Asia 38.16% Eas t Asia and Pacific 23.37% Middle Eas t and North Africa 11.29% Latin America and Cari bbean 11.45% Sub-Saharan Afri ca 23.04% North America Region 25.14% Europe and Central Asia -2% 0% 2% 4% 6% 8% 10% 12% 14% Source: EDGAR. Note: AAGR = average annual growth rate; GHG = greenhouse gas. Appendix A. Other EAP Energy Indicators 73 While the rapid EAP economic transformation has propelled domestic development and raised millions out of poverty, the growth has resulted in higher energy intensity compared to the Organisation for Economic Co- operation and Development (OECD) nations (IEA 2025). OECD economies have transitioned from manufacturing to service economies that typically have lower energy requirements. The implementation of energy efficiency regulations along with increased efficiency in electricity end uses and standards for buildings, vehicles, and appliances, have also played a significant role in reducing energy consumption in OECD economies. Table A.1 Energy Intensity/GDP (MJ/thousand 2015 US$) Energy Intensity/GDP (MJ/’000 2015 US$) Energy Intensity Trend (%) Country/Region 2001 2022 Vietnam 13,230 12,016 9.2 China 16,245 9,713 40.2 Indonesia 13,440 9,713 27.7 Philippines 10,509 6,448 38.6 OECD 5,987 4,019 32.9 OECD Europe 5,903 3,266 44.7 Source: Original compilation. Note: GDP = gross domestic product; MJ = megajoule; OECD = Organisation for Economic Co-operation and Development. Rising GDP levels in the EAP region are leading to an increase in electricity consumption. From 2001 to 2023, the growth of gross domestic product (GDP) per capita in the focus countries surpassed the increases in OECD countries. China experienced an increase of approximately 390 percent, Indonesia 115 percent, the Philippines 98 percent, and Vietnam 183 percent (World Bank n.d.). In contrast to OECD members, where per capita electricity consumption remained relatively stable despite increases in the GDP, the per capita electricity consumption has increased multifold in the focus countries—China by 470 percent, Indonesia by 210 percent, Vietnam by 700 percent, and the Philippines by 70 percent—attributed to the region’s industrialization, urbanization, and improvements in standards of living. With EAP economies heavily reliant on coal and more energy intensive compared to OECD economies, increasing electricity consumption results in larger GHG emissions relative to developed economies. Official Use Only OECD Europe 5,903 3,266 44.7 percent Rising GDP levels in the EAP are leading to an increase in electricity consumption. From 2001 to 2023, the growth of gross domestic product (GDP) per capita in the Focus Countries surpassed the increases in OECD countries. China experienced an increase of approximately 390 percent, Indonesia 115 percent, the Philippines 98 percent, and Vietnam 183 percent.132 In contrast to OECD members, where per capita electricity consumption remained 74relatively stable despite increases in the GDP, the per capita electricity consumption has increased multi-fold in the Focus Countries — China by 470 percent, Indonesia by 210 percent, Vietnam by 700 percent, and the Philippines by 70 percent – attributed to the region’s industrialization, urbanization, and improvements in standards of living. With EAP economies heavily reliant on coal and more energy intensive compared to OECD economies, increasing electricity Figure consumption A.4 GDP/Capita results in larger (thousands GHG at 2015 emissions US$ relative constant) to developed economies. , 2001–23 GDP/Capita ('000 at 2015 USD constant) 14 45 12 40 35 10 30 OECD Members Focus Countries 8 25 6 20 15 4 10 2 5 0 0 China Indonesia Philippines Vietnam OECD members Figure 37: GDP/Capita (Source: World Bank) Source: World Bank. Note: GDP = gross domestic product; OECD = Organisation for Economic Co-operation and Development. Figure A.5 Electricity Consumption (MWh/Capita), 2001–22 Electricity Consumption (MWh/Capita) 132 9 Bank, GDP per capita (constant 2015 USD) - https://data.worldbank.org/indicator/NY.GDP.PCAP.KD World Page |8 71 7 6 MWh/Capita 5 Official Use Only 4 3 2 1 0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 China Vietnam Indonesia Philippines OECD members Source: IEA. Figure 38: Electricity Consumption/Capita (Source: IEA) Note: MWh = megawatt-hour; OECD = Organisation for Economic Co-operation and Development. Appendix B. Energy Transition in Non-EAP Countries 75 Appendix B. Energy Transition in Non-EAP Countries Countries across other regions have successfully tapped into their domestic variable renewable energy (VRE) reserves to transition power sectors to clean generation. A total of 12 countries stand out as VRE “leaders,” selected on the basis that they have achieved a VRE share of more than 30 percent in generation.19 When compared to the focus countries, a majority of these VRE leaders have lower power generation/demand profiled, with the exception of: Chile (88 terawatt-hours [TWh]), the United Kingdom (285 TWh), Germany (520 TWh), and Spain (285 TWh). The energy transition in Denmark has been driven by a large share of wind energy in the generation mix, stemming from the country’s access to favorable wind resources in the Baltic Sea. Similarly, the power sector in the United Kingdom has benefited from the nation’s access to reliable wind reserves, with wind-based generation nearing 29 percent in 2023. On the contrary, Chile has benefited from large contributions of solar energy to decarbonize the power mix, with the country home to high solar irradiance levels, particularly in the Atacama Desert. Of the other countries that have successfully transitioned their power sectors (with a more than 80 percent share of renewable energy in generation) the majority have small annual generation volumes and are predominantly reliant on hydroelectric power generation: Nepal (10.7 TWh and 99 percent hydro), Paraguay (44.1 TWh and 99.5 percent hydro), Ethiopia (17.4 TWh and 96.7 percent hydro), and Uganda (5.8 TWh and 86.2 percent hydro), among others. These diverse generation mix profiles and power sector decarbonization approaches suggest that exploiting domestic energy resources is vital for driving an optimal energy transition. Countries in EAP must prioritize the development of the technically and economically feasible VRE and dispatchable renewable energy reserves to overhaul their power sectors. Of the countries leading VRE generation, the time frame to scale from roughly 10 percent to over 30 percent VRE share in generation has taken between 4 and 14 years. Generally, countries with smaller generation capacities have managed to expedite VRE share in generation relative to larger power markets. Uruguay, with a 2022 generation of 14.8 TWh, managed to scale its VRE share from 5.7 percent in 2014 to 35.2 percent of generation by 2018—in a period of four years. On the contrary, for countries with considerably larger power sector generation capacities—30 to 500+ TWh—such as Greece, Denmark, Germany, Ireland, Spain, Portugal, and the United Kingdom, it has taken almost a decade to scale VRE share from 10 percent to 30 percent, and this is despite being higher-income countries with more predictable demand growth rates. When comparing for income levels, countries with relatively smaller power sectors have managed to transition to a 30 percent VRE share at gross national income (GNI) levels of roughly US$15,000–US$24,000. The GNIs for countries with larger power sectors—Germany, Spain, and the Netherlands—were relatively high: US$30,000– US$60,000—when VRE shares crossed the 30 percent threshold in generation. Compared to these advanced economies, both Vietnam and China have managed to attain respectable VRE shares, exceeding 10 percent, at relatively lower GNIs (Vietnam was at US$4,110 and China was at US$13,390 in 2023). 19 Countries were preliminarily shortlisted based on the Ember Energy Electricity Data: https://ember-energy.org/data/yearly-electricity- data/. Generation mix data from the International Energy Agency (IEA) were used to plot the VRE share in generation (including solar photovoltaic, concentrated solar, and wind). Uruguay (2023) generation data were not available from IEA. Excluded countries were: (1) Djibouti—lack of generation data, and (2) Lebanon—high VRE share observed due to fall in overall generation. Official Use Only 76 Figure B.1 Countries Whose VRE Share in Generation Exceeds 30 Percent, 1999–2023 VRE Share in Generation  70.00% 60.00% 50.00% 40.00% 30.00% 20.00% 10.00% 0.00% 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 19 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 Denmark Lithuania Luxembourg Netherlands Uruguay Spain Greece Germany Portugal Ireland UK Chile Source: IEA. Note: VRE = variable renewable energy. Figure B.2 VRE Transition (10–30%) Time Frame and GNI VRE Transition (10 percent to 30 percent) Timeframe Years Generat ion (TWh) 16 600 14 500 Generation (TWh) - 2023 12 400 Number of Years 10 8 300 6 200 4 2 100 0 0 Uruguay huania Netherlands Li t Chile Luxembourg Greece Germany UK Ireland Denmark Spain Port ugal 30% VRE 2018c 2017 2022 2023 2023 2022 2020 2023 2019 2012 2021 2021 Year GNI (USD) 17,700 15,330 60,030 15,800 83,980 21,970 48,020 47,700 63,590 61,570 30,110 23,930 Source: IEA and World Bank. Note: GNI = gross national income TWh = terawatt-hour; VRE = variable renewable energy.   Appendix C. Overview of NDC and Power Sector Plan Targets 77 Appendix C. Overview of NDC and Power Sector Plan Targets Table C.1 Climate and Renewable Energy Targets NDC Metrics China Indonesia Vietnam Philippines Unconditional: 31.89 Unconditional: 15.8 Unconditional: 2.71 percent reduction by percent reduction by percent reduction by Lower CO2 emissions 2030 relative to 2010 2030 relative to 2014 2030 relative to 2010 per unit of GDP by baseline baseline baseline Emission reduction over 65 percent by targets Conditional: 43.2 Conditional: 43.5 Conditional: 72.29 2030 relative to the 2005 level percent reduction by percent reduction by percent reduction by 2030 relative to 2010 2030 relative to 2014 2030 relative to 2010 baseline baseline baseline At least 23 percent new and renewable by Primary energy 25 percent non-fossil 2025 mix targets fuel by 2030 At least 31 percent new and renewable by 2050 2030 (emissions 2030 (total emissions) reductions) Unconditional: 1,311 Energy sector Unconditional: 64.8 MtCO2e emissions MtCO2e Conditional: 1,223 Conditional: 227 MtCO2e MtCO2e PEP REF Scenario (2050) Revised PDP8 (2030) 3.3 GW—geothermal 14 GW—hydro 38 GW—onshore wind 32 GW—wind 17 GW—offshore wind 56 GW—solar (2030–35) 0.7 GW—bio RUPTL (2021–30) 73.4 GW—solar (capacity additions) 34.7 GW—hydro PEP CES1 Scenario (2050) By 2030 4.9 GW—bio 3 GW—geothermal Renewable energy 3.4 GW—geothermal 1,200 GW—solar and 10.5 GW—hydro capacity targets 0.6 GW—wind wind (achieved in Revised PDP8 (2050) 45.9 GW—wind (national plans) 4.7 GW—solar 2024) 54.7 GW—solar 91.4 GW—onshore 10.4 GW—hydro 0.7 GW—bio wind 0.6 GW—bio 130.1 GW—offshore PEP CES2 Scenario (2050) wind 3 GW—geothermal 295.6 GW—solar 10 GW—hydro 40.6 GW—hydro 65.9 GW—wind 9.5 GW—bio 35.7 GW—solar 0.7 GW—bio Source: Original compilation. Note: CES = Clean Energy Scenario; GDP = gross domestic product; GW = gigawatt; MtCO2e = million tons of carbon dioxide equivalent; NDC = Nationally Determined Contribution; PDP8 = Vietnam’s National Power Development Plan; PEP = Philippine Energy Plan; REF = Reference; RUPTL = Indonesia’s Electricity Supply Business Plan. Official Use Only 78 Appendix D. Secondary Barriers to VRE Scale-Up in EAP and Focus Countries Enabling Pillar I. National Ambition and Renewable Energy Target Misalignment in policy targets in Indonesia arises from institutional fragmentation and overlapping mandates among government agencies. The Ministry of Energy and Mineral Resources (MEMR) sets renewable energy targets but lacks authority to enforce compliance from Perusahaan Listrik Negara (PLN), the state-owned utility that dominates power sector planning and procurement. Meanwhile, the Ministry of State- Owned Enterprises (MSOE) is responsible for overseeing PLN’s management and commercial performance, while the Ministry of Finance (MOF) manages sector subsidies, borrowing limits, and guarantees. This fragmentation of responsibilities has posed challenges for effective planning and progress in the energy transition in recent years. Moreover, PLN’s role as the system planner, sole buyer, power producer, system operator, and transmission owner creates potential internal conflicts of interest. PLN’s decisions regarding planning, procurement, and operations may be influenced by the implications for its own generation and transmission businesses. PLN has been hesitant to pursue new investments without clear assurance of cost recovery, often facing differing objectives and targets from MEMR, MOF, and MSOE. Although each plan respects the overall policy objectives outlined in the National Energy Policy (KEN), they are developed separately by different entities and at different times, leading to inconsistencies and highlighting weak coordination among the National Energy General Plan (RUEN), National Electricity Plan (RUKN), and Electricity Supply Business Plan (RUPTL). Long-term targets vary significantly, as shown in the summary table D.1. Due to planning expertise and access to data, PLN’s planning document RUPTL has emerged as the primary planning document for the power sector, which is typically updated annually, guiding PLN’s investment decisions, further establishing its dominant position in the sector. Table D.1 Indonesia—Policy Mismatch RPJPN/RPJMN Parameter KEN RUEN RUKN 2024–60 RUPTL 2021–30 2025 Responsible DEN—MEMR MEMR MEMR PLN Bappenas ministry House of Approver President Ministry Ministry President representatives Current period 2014–50 2017–50 2024–60 2021–30 2005–25/ 2020–24 Renewal period 2024–60 - 2029 (expected) 2023–32 2025–45/2025–29 51.6% renewable energy (of Renewable 23% by 2025 31% 23% by 2025 39% new capacity energy share 73.6% by 2060 23% by 2024 by 2050 by 2050 additions) target between 2021 and 2030 Appendix D. Secondary Barriers to VRE Scale-Up in EAP and Focus Countries 79 RPJPN/RPJMN Parameter KEN RUEN RUKN 2024–60 RUPTL 2021–30 2025 NRE share Mix target by Mix target by (Generation): 2025: 2025: 1. 2025: 15.9% NRE: 23% Mix target 2025: NRE: 23% 2. 2030: 20.1% 1. NRE: 23% 1. 6–7% per year 3. 2040: 41.3% 1. Meet 2. Oil: 25% GDP growth 2. Energy 4. 2050: 64.7% Indonesia’s 3. Coal: 30% intensity 5. 2060: 73.6% electricity 4. Gas: 22% 2. 5% poverty reduction: 1%/ demand Target reduction year Mix target 2060: growth (avg. Mix target 2050: 1. New energy: 4.9%/year) 1. NRE: 31% 3. 5% 3. Reduction 24.1% 2. Oil: 20% unemployment in final energy 2. VRE: 20.7% 2. 40,575 MW 3. Coal: 20% reduction consumption: 3. Non-VRE: of new power 4. Gas: 24% 17% by 2025 28.8% generation 39% by 2050 4. Fossil + CCS: capacity 26.4% Source: ETP (2023b). Note: Bappenas = Ministry of National Development Planning; CCS = carbon capture and storage; DEN = National Energy Council; MW = megawatt; KEN = National Energy Policy; MEMR = Ministry of Energy and Mineral Resources; NRE = new renewable energy; PLN = state-owned power utility; RPJMN = Medium-term National Development Plan; RPJPN = National Long-Term Development Plan; RUEN = National Energy General Plan; RUKN = National Electricity Plan; RUPTL = Indonesia’s Electricity Supply Business Plan; VRE = variable renewable energy. Enabling Pillar II. Enabling Policies, Regulatory Frameworks, and Supporting Initiatives Most cross-border regional power trade activities are limited to bilateral agreements rather than through a fully integrated market. Examples include the Lao People’s Democratic Republic–Thailand–Malaysia– Singapore Power Integration Project (LTMS PIP), which facilitates the export of up to 100 megawatts of renewables from the Lao PDR to Singapore; Vietnam’s import of wind energy from Lao PDR; and Thailand’s import of hydroelectricity from Lao PDR. However, broader regional integration is yet to yield its benefits. Singapore, with its limited VRE potential, is relying on clean energy import projects and cooperation from its neighbors to meet its climate targets. Success of these projects depends on bilateral dialogues and a mutually beneficial arrangement. Under current Indonesian regulations, independent power producers cannot enter into direct agreements with commercial and industrial consumers, restricting businesses’ ability to procure clean energy. PLN’s Renewable Energy Certificate (REC) program does not offer the long-term price stability or additional renewable capacity that many multinational and export-oriented industries with net-zero commitments require. Implementing market reforms is essential for enabling corporate power purchase agreements (PPAs) and fostering private sector–led deployment. Procurement of VRE in Indonesia has been undertaken in two stages: prequalification and proposal submission (JETP Indonesia 2023). Developers must first apply for PLN’s List of Selected Providers (Daftar Penyedia Terseleksi, DPT) and meet certain administrative, technical, and financial requirements. However, the DPT application process is often perceived as unclear and inconsistent, often with specific conditions aligned with a limited set of developers, lacking a defined timeline and with approval taking anywhere from a few weeks Official Use Only 80 to over a year (IEEFA 2024b). For the proposal submission stage, PLN issues a Request for Proposal only to DPT-registered companies, with PR 112/2022 mandating the procurement lead time of 90 days for direct appointment and 180 days for the direct selection process. However, the actual implementation of the tender often experiences delays, extending well beyond the specified time frames. For example, the Hijaunesia Project in 2023, launched by PLN’s subsidiary (PLN Indonesia Power) for a 1 gigawatt (GW) large-scale solar power plant, has been ongoing for nearly two years without finalizing the tender results (Indonesia Business Post 2024). Despite Vietnam’s nearly 600 GW offshore wind potential, the regulatory environment adds an element of uncertainty to unlocking offshore wind resources. Development in the country has been held back by the lack of a regulatory framework on marine spatial planning, leasing, and route to market—deterring project development, financing, and shaking investor confidence (GWEC 2024). Only a limited number of offshore wind projects have been granted a survey license with limited progress to date—for example, Enterprize Energy has been undertaking survey activities since 2019. Decree 11 which regulates allocation of sea areas, lacks clarity on allocation of sea areas to non-SOEs (state-owned enterprises), primarily foreign companies. Decree 58 clarifies the conditions for participation of foreign entities but enforces partnerships with SOEs, which must hold at least 5 percent of the charter capital or total voting shares. Additionally, a map of sea areas has yet to be finalized and published and since sea area allocation decisions are rendered after the approval of an Environmental Impact Assessment, investors are left with uncertainty on sea area rights. The framework lacked clarity on the authority responsible for assigning sea areas, granting permissions, and approving activities such as monitoring and surveying, but the responsibility has since been assigned to the Ministry of Agriculture and Environment under Decree 58. Delays in regulatory reforms and uncertainty about the governing framework has led companies like Equinor and Ørsted to exit the offshore wind market in Vietnam. The New Electricity Law, adopted by the National Assembly on November 30, 2024, includes regulations regarding the competitive selection process, requiring the government to include a draft PPA in the bidding dossier. The government is also tasked with drafting and issuing a new decree to provide further details on specific regulations related to the selection of investors. The forthcoming draft decree should clarify how to develop a bankable PPA and outline the extent to which bidders can negotiate and mark up the draft PPA in response to the invitation-to-bid dossier. It will also set guidelines on what changes are permissible and what are not. Until these clarifications are made, concerns regarding certainty and bankability persist. The Philippines has made incremental progress toward electricity market liberalization, but competition remains constrained by high market concentration in both the generation and retail segments. A limited number of players continue to dominate the supply, limiting consumer choice and competitive pricing outcomes. Efforts to operationalize the Retail Competition and Open Access (RCOA) framework have been delayed by legal and regulatory setbacks, most notably a 2017 Supreme Court ruling that invalidated mandatory migration provisions, reinforcing the principle of voluntary participation (Power Philippines 2017). While the Energy Regulatory Commission (ERC) has resumed implementation and lowered the eligibility threshold for contestable customers to 500 kilowatts (kW), actual market participation remains limited due to low consumer awareness, administrative complexity, and unclear switching procedures. Similarly, the Green Energy Option Program, which enables direct procurement of renewables for qualified consumers, has seen slow uptake owing to limited promotion and unresolved implementation barriers. Appendix D. Secondary Barriers to VRE Scale-Up in EAP and Focus Countries 81 Enabling Pillar III. Infrastructure and System Operations The current power dispatch rules in China are based on a fair dispatch policy where generators produce an allocated amount of energy as opposed to an economic dispatch system, which prioritizes generators competing based on their short-run marginal costs. Fair dispatch rules have secured power offtake for generators and served as an incentive for development of coal capacity in the country. The existing rules result in energy wastage as the more efficient VRE plants compete with inefficient thermal generators for power delivery. Economic dispatch rules are favored by most countries as they ensure the integration of VRE, reduce curtailment, and ensure power from inefficient coal plants is not dispatched prior to VRE. Indonesia’s reliance on large, inflexible fossil fuel power plants exacerbates integration challenges. These thermal plants struggle to operate at lower loads, and contractual structures such as take-or-pay provisions in PPAs require PLN to prioritize contracted fossil generation, reducing operational flexibility. Enabling Pillar IV. Financing and Investment Climate The levelized cost of energy (LCOE) for solar+battery remains significantly higher than coal in most EAP markets, with cost multiples ranging from 1.7 times in the Philippines to 2.8 times in China. This reinforces the affordability gap, particularly when energy storage is required for dispatchability and grid reliability. Cost competitiveness of combined VRE and storage solutions in emerging markets is currently hindered by limited scale and market structures. In China, the scale of VRE additions and a robust domestic manufacturing base have driven costs downward—with wind+battery LCOE (US$51.49/megawatt-hour [MWh]) now lower than coal (US$63.06/MWh). However, the solar+battery LCOE (US$68.14/MWh) is nearly 80 percent higher than the solar-only LCOE (US$38.05/MWh) in China (Wood Mackenzie 2024). Other markets in EAP have yet to achieve sufficient scale to replicate similar cost efficiencies. Achieving cost parity will require well-structured tariff frameworks and competitive procurement mechanisms. Figure D.1 Focus Countries: LCOE Breakdown LCOE Breakdown (2023) 140 China Indonesia Philippines Vietnam 120 100 80 $/MWh 60 40 20 2.8x 1.8x 1.7x 1.9x 0 Coal Sol ar+Battery Coal Sol ar+Battery Coal Sol ar+Battery Coal Sol ar+Battery Capital Cost Fixed OPEX Variable OPEX Other OPEX Fuel Carbon Taxes Source: Wood Mackenzie. Note: LCOE = levelized cost of energy; MWh = megawatt-hour; OPEX = operational expenditure.   Official Use Only 82 Appendix E. Additional Pathways for Accelerating VRE Deployment in EAP and Focus Countries Enabling Pillar II. Enabling Policies, Regulatory Frameworks, and Supporting Initiatives To kick-start the offshore wind market, Vietnam must streamline the offshore wind development process and clarify the roles of different stakeholders. Paramount to the development of offshore wind is clarity and transparency for investors on the stakeholders involved, locations for development, and streamlining of the licensing and permitting process. Vietnam should consider establishing a one-stop shop , which would be instrumental in simplifying the complicated permitting process involved in offshore wind development. The New Electricity Law also presents an opportunity to institutionalize a robust competitive bidding framework and aligns it with broader power sector reforms. A well-designed procurement framework, accompanied by a detailed investment plan under the Revised PDP8, can help crowd in both domestic and international capital, reduce procurement costs, and accelerate the realization of Vietnam’s clean energy targets. The Philippines should accelerate the expansion of the contestable retail market by fully operationalizing the RCOA framework and broadening access to direct renewable energy procurement. The ERC has already lowered the eligibility threshold to 500 kW and intends to reduce it further to 100 kW within the next 3–4 years; this roadmap should be supported by enhanced consumer education, simplified switching procedures, and enforcement of fair access rules for retailers to compete. In parallel, the Green Energy Option Program— which allows customers with at least 100 kW demand to contract directly with renewable energy suppliers— should be further promoted and streamlined. This includes standardizing corporate PPA templates, publishing clear wheeling and grid access rules, and addressing transaction costs to unlock greater corporate demand for renewables. Enabling Pillar III. Infrastructure and System Operations China must adopt market-based medium- and long-term contracts for interprovincial trade. Amendments are needed to the presently used, government negotiated, unidirectional long-term contracts to incentivize long-distance transmission. Moving to market-based medium- and long-term contracts, with VRE developers having equal access to grids, can ensure that cross-provincial capacities can be used more flexibly. Establishing merit-based rules that favor dispatch of power from VRE and the most energy-efficient power plants will further incentivize the integration of clean energy. Economic dispatch is essential to decouple coal capacity from generation—minimizing the role of inefficient thermal generation in meeting peak demand. The Philippines should evaluate integration of offshore wind projects into Competitive Renewable Energy Zones (CREZ) to support national transmission planning. Linking offshore wind zones to onshore CREZs can support strategic and expedited investments in transmission infrastructure for unlocking the VRE potential offered by the nation’s vast offshore wind resources.