Asian Power (September 2026-March 2027)

Issue No. 118

ISSUE 118 | DISPLAY TO 31 MARCH 2027 | www.asian-power.com | A Charlton Media Group publication

Asian Power

PAYING MORE FOR LESS WHY DO POWER SHOCKS HIT PHILIPPINE BILLS SO HARD?

US$360P.A.

INDONESIA SETS 2032 FOR NUCLEAR DEBUT SUPER EL NIÑO PUTS ASIA’S GRIDS ON EDGE AI POWER DEMAND REVIVES SINGAPORE’S FUSION BET

FROM THE EDITOR PERMIT NO. MDDI (P) 038/07/2025

F

ilipino households are paying some of Southeast Asia’s highest electricity prices, and the reasons go well beyond fuel alone.

Imported coal and LNG, a weaker peso, and an expensive, fragmented transmission network all feed into monthly bills. On page 10, we look at why power remains costly even as regulators and utilities try to ease the pressure.

PUBLISHER & EDITOR-IN-CHIEF Tim Charlton EDITORIAL MANAGER Tessa Distor PRINT PRODUCTION EDITOR Vienna Verzo LEAD JOURNALIST Jaleen Ramos JOURNALISTS Gwyneth Marie Bejer Alec Maquiling-Cruz Sam Bernardo Ibnu Prabowo Miguel Dumlao GRAPHIC ARTIST Cathlyn De Raya EDITORIAL ASSISTANT Dylan Afuang COMMERCIAL MEDIA TEAM Jenelle Samantila Dana Cruz Danielle Goh

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That cost story sits alongside a growing reliability risk. A potential Super El Niño could tighten power systems across Asia in sequence, first by weakening hydropower in Southeast Asia and later by pushing up electricity demand as temperatures rise elsewhere. The pressure may not peak everywhere at once, which makes timing especially important for utilities. Turn to page 24.

Singapore is facing a different equation, with AI and data-centre growth sharpening the need for firm power just as experts remain divided on when fusion could make a meaningful contribution. We examine that debate on page 8.

Indonesia, meanwhile, has finally moved nuclear into its formal energy strategy, with its first 250-megawatt reactor targeted for 2032. The next test is whether grid strength, regulation and institutional readiness can support what comes after. See page 20.

Tim Charlton

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ASIAN POWER 1

CONTENTS

12

EXCLUSIVE RESEARCH 10 AP WHY DO POWER SHOCKS HIT PH BILLS SO HARD?

FIRST

INTERVIEW PGE BUILDS PLANT DATA INTO GEOTHERMAL DESIGN

ANALYSIS

EL NIÑO MAY TEST ASIAN 24 SUPER POWER GRIDS IN WAVES

MARKET REPORT

06 Fragmented tenders slow APAC renewables 07 AI demand raises heat on data centres in Hong Kong

VOX POP

20 Indonesia sets 2032 target for first nuclear power plant 22 Carbon tax clarifies costs, risks widen

COMMENTARY

08 AI power demand revives Singapore fusion debate

INTERVIEW

30 Scaling for resilience: What APAC’s bioenergy markets can learn from each other 32 Why bigger digesters alone won’t solve Asia’s renewable energy challenge

18 Towngas takes hydrogen to sites, data centres

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ASIAN POWER 3

News from asian-power.com Daily news from Asia

POWER UTILITY

POWER UTILITY

PROJECT

Data centre growth to drive LNG demand, gas turbines in SEA

Malaysia exceeds 2025 renewable target at 32% capacity

Singapore power use rises as data centres triple demand

Data centre expansion is set to drive combined-cycle gas turbine development and LNG demand in Southeast Asia as the region’s pipeline more than triples to 9.4 gigawatts by 2035, Wood Mackenzie said. LNG demand in the region is expected to grow 16% annually through 2035.

Malaysia’s installed renewable energy capacity hit 32%, surpassing the 31% target set for 2025, according to a sector report by Maybank Investment Bank Berhad. Global investment in energy transition rose to $2.3t in 2025, up 8% YoY, driven by electrified transport and renewable energy.

Singapore’s artificial intelligencedriven data centre growth is set to sharply increase electricity demand, with usage expected to “almost triple from 2025 to 2030,” placing pressure on grid capacity, costs, and emissions targets, according to Bob Johnson, VP analyst at Gartner.

REGULATION

TECHNOLOGY

PROJECT

Thailand halts 4 GW of gas-fired power amidst oversupply

Grid-forming inverters seize control to stabilise Asia’s power

Amogy, LOTTE Fine Chemical to develop ammonia-to-power projects

Thailand has suspended 4 GW of gasfired power capacity and delayed a new plant, signalling a major shift in its energy strategy amidst electricity oversupply. In October, the National Energy Policy Council ordered the suspension of four power plants, including three gas-fired facilities totalling 4GW.

Grid-forming inverters, which help electricity systems maintain steady voltage and frequency, are becoming essential in Asia as demand for electricity outpaces grid upgrades.

Utilities are turning to these inverters to support networks strained by growing renewable energy, large digital loads, and industrial expansion.

Amogy and LOTTE Fine Chemical have signed a memorandum of understanding to jointly develop ammonia-to-hydrogen and ammoniato-power solutions in South Korea.

The companies will explore hydrogen refuelling infrastructure, distributed ammonia-to-power generation, and marine ammonia bunkering.

POWER AND FINANCE | Q3 2021 4 ASIAN ASIAN BANKING

ASIAN POWER 5

FIRST HONG KONG CLEANPOWER PUSH NEEDS CERTIFICATION ENVIRONMENT

H

ong Kong can put more zero-carbon electricity on the grid, but companies still need a credible way to verify that the power they buy is actually clean.

As the city targets up to 70% zerocarbon power by 2035, certification, reliability and market rules will determine whether businesses can turn that supply into measurable emissions cuts.

Christine Loh, chief development strategist at the Institute for the Environment at the Hong Kong University of Science and Technology, said the government and power companies could introduce a certification system that lets businesses buy verified zero-carbon electricity, similar to programmes already available in China.

The issue is becoming more important as companies face tighter disclosure requirements for emissions linked to the electricity they consume.

Power-intensive demand “More companies are now required to disclose emissions linked to the electricity they use, making access to cleaner power increasingly important,” Lawrence Iu, executive director at Civic Exchange, told Asian Power.

Secretary for Environment and Ecology Tse Chin-wan told the Legislative Council in July that Hong Kong plans to raise zero-carbon electricity from about 25% of the fuel mix to as much as 70% by 2035, mainly through additional clean-energy imports from mainland China.

Iu said the shift could be particularly relevant for electricityintensive industries including AI, data centres, life sciences, advanced manufacturing and financial services as the Northern Metropolis develops.

But whether cleaner supply becomes a competitive advantage will depend on its reliability, affordability and the market framework around it.

6 ASIAN POWER

Developers cite grid, contracting, and documentation hurdles

Fragmented tenders slow APAC renewables PROJECT

A

sia-Pacific attracted a record $68.6b in renewable energy infrastructure investment in 2025, but developers still reported the world’s least efficient procurement processes as fragmented tenders, grid constraints and contract risks slowed project delivery.

Only 24% of respondents in the region described their most recent procurement process as very efficient, the lowest share globally.

At the same time, investment rose 17% from 2024, whilst 62% expected strong investment growth, the highest of any region.

The findings came from the 2026 Renewable Energy Infrastructure Outlook, published on 31 March by Ansarada Pty Ltd. in partnership with Infralogic. The survey covered 150 senior executives across APAC, Europe, the Middle East and Africa, and the Americas.

Renewable energy investment depends on grid conditions and market design as much as capital spending, Edward Zhao, global

Edward Zhao

Rohit Anand

senior vice-president and Singapore general manager at Univers Pte. Ltd., told Asian Power.

“It depends on more than just how much money you put into capital expenditure.”

Zhao said renewable energy projects depend on more than funding because developers must also consider electricity market rules, transmission capacity, and grid reliability.

“It is an interrelated topic that is part of the power system,” he said.

“You need to consider market regulation, market mechanisms, grid resilience, flexibility, and affordability.”

Only 22% of respondents in APAC said risks were allocated effectively in their most recent tender, the lowest regional result in the survey.

Zhao said bigger projects become harder to deliver because engineering, operations, and electricity market risks increase together.

“The bigger the project becomes, the more impact it brings to the entire power system,” he said.

Biggest delivery risk Rohit Anand, managing director and head of Asia infrastructure and climate direct investments at British International Investment Plc (BII), said fragmented procurement across Southeast Asia remains a major barrier.

“You need to have a large volume of tenders to allow the industry to scale, and very fragmented procurement makes it difficult,” he said in a separate interview.

Anand said some power purchase agreements also discourage investment because they allow government buyers to suspend electricity purchases after projects have been financed and built.

“If you are investing a large sum of money assuming that electricity will be bought for 20 years, the buyer of electricity cannot have a unilateral right to just decide one day to stop buying that power,” he said.

The Ansarada report found that 46% of respondents in APAC identified supply chain disruption as their biggest delivery risk, whilst 54% cited documentation as a key procurement challenge, the highest share of any region.

Organisations in the region also used an average of 3.1 procurement platforms, suggesting many processes remain spread across multiple systems.

FIRST

Utilities limit coal buying amidst uncertainty over the disruption duration

AI demand raises heat on data centres in Hong Kong

H

TECHNOLOGY

ong Kong data centre operators may need to go beyond mandatory energy efficiency requirements as artificial intelligence (AI) increases power consumption and heat in a city warming more than twice as fast as before, analysts said.

“The government or data centre owners may consider setting absolute energy, water, and carbon targets, in addition to those for efficiency,” said Harry Lai, executive director of the Hong Kong Green Building Council.

The government will extend mandatory energy efficiency requirements to data centres from 20 September, requiring energy audits

at least once every five years and disclosure of technical information.

Operators will not be required to implement measures identified by those audits, and the government has not set a limit on how efficiently data centres use power.

Efficiency measures alone may not show whether facilities are consuming more resources as they expand, Lai said.

Hong Kong’s rising temperatures add to the cooling challenge.

The city warmed by 0.35°C per decade from 1996 to 2025, more than twice the rate recorded over the longer period from 1885 to 2025, according to the Hong Kong Observatory.

Harry Lai

Chris Howard

Shipeng Yan

The first half was also unusually warm, with the average low of 21.5°C the highest recorded for the period and the average high of 26°C the second highest.

Traditional air cooling is becoming less suitable for AI systems, which can use up to eight times as much power per server rack as older equipment, said Chris Howard, head of account management for data centres at Jones Lang LaSalle Ltd. (JLL) in the Asia-Pacific region.

Operators are shifting to liquid cooling, which removes heat closer to processors, Howard said.

Backup systems are needed because temperatures can rise quickly if liquid flow stops, he pointed out.

AI systems might also require more floor space for batteries, electrical equipment, and transformers because of their higher power requirements, he said.

The concentration of several facilities in one area could add to local heat loads, said Shipeng Yan, assistant professor of management and strategy at The University of Hong Kong.

The Hong Kong government broke ground in March on the Sandy Ridge Data Facility Cluster in the Northern Metropolis. The cluster could consume about 1.75 billion kilowatt-hours of electricity a year, according to a March estimate

by The Green Earth Ltd. “Data centre design should also consider physical climate risks,” Yan said in an interview.

THE CHARTIST: CHINA AVOIDS $176.8B IN FOSSIL FUEL COSTS

A

sian economies led global fossil fuel cost avoidance from renewable power growth in 2025, according to a report published by the International Renewable Energy Agency (IRENA).

China accounted for the largest share globally at $177b in avoided fossil fuel costs in 2025, followed by India at $18b and Japan at $15b. Indonesia, Thailand, and the Philippines combined avoided $5.7b in coal and gas imports over the same period.

Across 20 major economies covering most renewable generation, renewable power avoided $377b in fossil fuel purchases.

Globally, renewables avoided $480b in fossilfuel costs in 2025.

“The decline in renewable energy costs is delivering a powerful economic dividend,” according to Francesco La Camera, director-

general of the global organisation.

Solar photovoltaic cost stood at $44 per megawatt-hour (MWh), onshore wind at $33, and offshore wind at $78.

New gas-fired generation reached near $100/MWh in some markets, whilst a turbine shortage doubled capital costs for combinedcycle plants in the United States.

Clean-tech manufacturing investment halved from a quarterly peak of $70b in 2023 to $35b by the end of 2025, whilst commodity and component prices rose over the same period.

“IRENA’s analysis proves yet again the financial benefits of investing in clean energy as a buffer to a volatile world,” said Murat Kurum, President-Designate for COP31.

Over 90% of utility-scale renewable capacity added in 2025 was cheaper than the lowestcost fossil alternative.

Avoided fossil fuel costs in 2025

Source: IRENA Renewable Power Generation Costs in 2025 report Notes: (1) Mexico 2.9; (2) Indonesia 2.6; (3) Malaysia 2.0; (4) Argentina 1.6; (5) Philippines 1.4; (6) South Africa 0.8

ASIAN POWER 7

VOX POP

AI power demand revives Singapore fusion debate APAC

S

ingapore’s push to support artificial intelligence (AI)driven growth is putting fusion power in the spotlight.

However, experts disagree by decades on when the technology could contribute to the city-state’s electricity supply.

The Ministry of Trade and Industry raised Singapore’s 2026 growth forecast to 4.5% to 5.5% in August, citing stronger global spending on AI. The stronger economy is expected to lift electricity demand as Singapore relies almost entirely on imported fuel, has limited land for renewable energy, and faces growing power needs from data centres.

Solar remains the only viable domestic renewable, but land scarcity in the city-state caps how far it can scale, whilst alternatives

It remains an emerging technology, and no fusion power plant has yet demonstrated commercial electricity production

such as hydrogen-fired turbines, enhanced geothermal, and regional grid imports are either unavailable at scale or come at a steep cost.

Effectively domestic Fusion has gained momentum since the National Ignition Facility (NIF) achieved ignition in December 2022, drawing billions of dollars in private investment into companies seeking to commercialise the technology.

Proponents argue the technology could deliver firm, carbon-free power from a fuel that is effectively domestic, since it is derived from water—a contrast to Singapore’s near-total reliance on imported natural gas.

Singapore is also positioning itself in the sector.

Commonwealth Fusion Systems LLC (CFS) signed a research agreement with the Agency for

Science, Technology and Research (A*STAR) in May, whilst its chief executive identified Singapore as a potential hub for fusion energy.

Its financial depth, engineering talent, and research ecosystem have also drawn interest from other fusion developers exploring longterm partnerships in the region.

But the technology’s potential contribution to Singapore’s power mix remains uncertain.

No fusion power plant has yet demonstrated commercial electricity production, and building systems that operate reliably, generate power economically, and meet safety and regulatory requirements remains a formidable engineering challenge.

Industry projections point to possible commercial deployment in the mid-2030s, whilst independent analysis puts a meaningful role much further out, potentially beyond 2050.

Asian Power spoke with a fusion developer, an academic researcher, and an industry analyst to assess the technology’s prospects and its potential role in Singapore’s electricity system.

EXPERT OPINION

THOMAS FORNER CEO and co-founder, Focused Energy GmbH

S

ingapore sits at the intersection of two forces defining this decade: electricity demand driven by artificial intelligence (AI) and near-total dependence on imported fuel. It’s a position comparable to Germany’s, though with less AI-driven growth.

Fusion addresses both sides of that equation—it delivers firm, carbon-free power from a fuel that is effectively domestic since it’s made from water, allowing Singapore to move towards energy independence.

Singapore also has a compelling ecosystem.

It has always been a bridge to Asia, with substantial capital available and strong universities for research. That is why we’ve been building relationships in Singapore for more than four years now. We see Singapore as a partner, a potential off-taker, and a hub for the broader Asian market.

We've been in touch with several companies where we have letters of intent and are working on ideas for different projects—for example, A*STAR and [Singapore Technologies Engineering Ltd.], both of which are part of Singapore’s supply chain or research ecosystem.

8 ASIAN POWER

XAVIER GARBET Professor, Nanyang Technological University

F

usion could become part of Singapore’s power mix, but not in the near future. It remains an emerging technology, and no fusion power plant has yet demonstrated commercial electricity production. Before fusion can contribute to Singapore’s power mix, scientists and engineers must prove that fusion systems can operate reliably, generate electricity economically, and meet stringent safety and regulatory requirements.

Most fusion companies are aiming for their first commercial plants in the 2030s, but these timelines remain ambitious and uncertain. The largest fusion experiment under construction, the International Thermonuclear Experimental Reactor (ITER), is expected to begin operating in the mid-2030s—though ITER is a scientific and engineering demonstration facility rather than a commercial power plant, and significant development will still be required before fusion can be deployed at scale.

Singapore is taking a pragmatic approach by building expertise today, particularly through programmes at Nanyang Technological University and A*STAR.

PRAKASH SHARMA Vice president and head of scenarios and technologies, Wood Mackenzie Ltd.

S

ingapore is a potential market for next-generation nuclear, including SMR (small modular reactor) nuclear and fusion, given its ambition to decarbonise the energy systems and achieve 24/7 clean firm power supply.

The government is exploring all technology options to improve energy security and has not committed to a timeline for nuclear. We think it’s a post-2050 opportunity for a meaningful contribution to the power mix.

Singapore is an energy-disadvantaged country due to its limited land, high population density, and reliance on energy imports. But the same constraints that make Singapore energy-poor make it a strong candidate for nuclear [power].

Solar is the only viable domestic renewable, but land scarcity caps developments. The alternative sources for firm power supply, hydrogen-fired turbines, enhanced geothermal, and regional grid imports, are either not available at scale or will come at a levelised cost of north of $250 per megawatt-hour.

ASIAN POWER 9

AP EXCLUSIVE RESEARCH

Why do power shocks hit PH bills so hard?

Imported fuel and grid costs continue to drive electricity bills higher.

L

PHILIPPINES

ea Mariño, 55, barely had time to complain about the heat before another shock arrived: her electricity bill.

When Manila Electric Co. (Meralco) raised residential rates in April, the compliance officer and mother of three had little choice but to absorb another household expense despite already rising living costs.

“The increase was far too big,” Mariño told Asian Power. “But we don’t really have a choice. We’d rather pay than have our electricity cut off.”

For Joy Sevilla, a 59-year-old mom-and-pop store owner, the frustration was not limited to the amount due.

“It’s unfair,” she said in mixed English and Filipino. “There are so many charges on the bill that don’t seem like consumers should be paying, on top of our taxes.”

Their complaints reflect a broader problem. Filipino households pay some of Southeast Asia’s highest electricity prices because the country relies heavily on imported fuel, operates one of the region’s most complex power grids, and passes much of those costs directly to consumers.

Apparent increase GlobalPetrolPrices data for the first quarter of 2026 placed Philippine residential electricity prices at about $0.21 per kilowatthour (kWh), second amongst six major Southeast Asian economies surveyed and behind only Singapore at $0.232 per kWh. The increase became more apparent in April. Meralco, the country’s biggest private electric distribution utility serving more than 8.2 million customers in Metro Manila and nearby provinces, raised the residential rate by $0.0087 (PHP0.53) to $0.23 (PHP14.35) per kWh from the previous month.

A household consuming 200 kWh paid about $1.75 (PHP107) more, with larger increases for homes using more electricity.

Although the rate eased slightly in May after an Energy Regulatory Commission (ERC) refund order, 10 ASIAN POWER

With over 7,000 islands, the Philippines cannot build a single power grid like its mainland neighbours

It’s unfair. There are so many charges on the bill that don’t seem like consumers should be paying

Patrick Tan

Cynthia Alabanza

electricity remained expensive by regional standards.

The electric distribution utility raised rates again in June to $0.23 (PHP14.48) per kWh, the highest monthly residential rate on record.

A Philippine electricity bill combines generation, transmission, distribution, taxes, and other regulated charges. Some are controlled by regulators, whilst others rise or fall with fuel prices, exchange rates, and conditions across the national power system.

The framework dates back to the Electric Power Industry Reform Act of 2001, better known as EPIRA, which separated electricity generation, transmission, and distribution to encourage competition in power generation whilst keeping the grid and distribution networks regulated.

Imported fuel burden Patrick Tan, head of wider Asia at Aurora Energy Research, said the Philippines remains one of the few fully liberalised electricity markets in Southeast Asia.

He said Malaysia, Thailand, and Indonesia benefit from bigger domestic fuel resources or regulated pricing systems that shield consumers from much of

the volatility in international fuel markets. Philippine consumers absorb more of those costs through their monthly electricity bills.

“The Philippines does not have the luxury of those resources,” Tan said.

Gas plants once supplied by the Malampaya field progressively run on imported liquefied natural gas (LNG), he told the magazine, tying that portion of the Philippines’ supply to global markets.

Unlike Malaysia and Indonesia, which produce much of their own fuel, the Philippines imports most of the coal and LNG used by its power plants. Those purchases are priced in dollars, leaving electricity costs exposed to swings in global energy markets and the pesodollar exchange rate.

That exposure has become more pronounced as domestic gas production declines and imported LNG supplies a growing share of electricity demand.

Department of Energy (DOE) data showed that coal accounted for 57.2% of the Philippines’ electric generation in 2025. Most of that coal was imported, making generation costs vulnerable whenever global coal prices or the peso move sharply.

The peso’s depreciation to PHP60.748 against the dollar for the

AP EXCLUSIVE RESEARCH Residential and business electricity prices by country

Katrina Garcia-Amuyot

Source: Asian Power

March supply month alone added about $0.0086 (PHP0.5257) per kWh to April’s generation charge.

Comparisons with neighbouring countries often overlook those structural differences, Tan said.

Fuel, however, explains only part of the story. The Philippines is an archipelago of more than 7,000 islands, making it impossible to build a single interconnected transmission network like those serving most mainland Southeast Asian countries.

Electricity must travel across separate island grids linked by submarine cables and high-voltage transmission lines, increasing both construction and maintenance costs.

May power squeeze The Asian Development Bank estimates the country needs about $10b in transmission investment to boost and expand the grid as electricity demand continues to grow.

Those costs also appear on consumers’ monthly bills.

Transmission charges rose sharply in March after National Grid Corporation of the Philippines (NGCP) increased spending to keep the grid stable, accounting for nearly half of that month’s transmission charge, Meralco said in an advisory.

Higher fuel costs, a weaker peso, and a transmission network that is expensive to build and maintain have combined to keep Philippine electricity prices amongst the highest in the region.

Those pressures became even more visible in May, when transmission failures and power shortages pushed wholesale electricity prices sharply higher.

Wholesale electricity prices

climbed in May after the Luzon grid entered one of its most severe supply squeezes in recent years, exposing how quickly generation and transmission failures can filter through to consumers.

The pressure had been building before the power failures. Twentyseven power plants in Luzon were offline or operating below capacity, some since 2019, whilst record temperatures pushed electricity demand to successive highs.

Within a week, the grid broke its all-time peak demand record twice, National Grid Corporation of the Philippines spokesperson Cynthia Alabanza told Asian Power.

The Visayas grid was also under a yellow alert on 12 May, with power reserves below the transmission grid’s contingency requirement, limiting the support it could provide to Luzon if supply tightened further.

The situation worsened on 13 May when the Ilijan–Dasmariñas and Ilijan–Tayabas 500-kilovolt transmission lines tripped, disconnecting more than 2,400 megawatts of generating capacity from the Luzon grid.

The power failures triggered manual load dropping that affected about 3.9 million customers across Metro Manila and parts of the main Luzon island. Several large power plants could no longer deliver electricity to the grid, forcing the system into a multi-day red alert.

Katrina A. Garcia-Amuyot, senior manager for metering, registration, and stakeholder services at the Independent Electricity Market Operator of the Philippines (IEMOP), said the loss of transmission capacity sharply

Mario Marasigan

If power plants are delayed whilst transmission projects are completed on time, there’s a mismatch

reduced available supply during a period of heavy electricity use.

“The price determination process in WESM during that period functioned as designed,” she said, referring to the Wholesale Electricity Spot Market. Prices there climbed to about PHP10 to PHP11 per kWh during the affected trading intervals as the market relied on more expensive generating units to meet demand.

Garcia-Amuyot said the increase reflected tighter supply rather than a failure of the market itself. She said market safeguards, including the secondary price cap that limits extreme price spikes during severe supply shortages, were activated during parts of the alert period.

Several pressures Despite the May spike, very high wholesale prices remain uncommon. IEMOP data showed the secondary price cap was triggered during less than 1% of all trading intervals in both 2025 and the first five months of 2026.

The May disruption showed how several pressures converged at the same time. High temperatures increased electricity demand, power plants that were shut down for maintenance or unexpected problems reduced available supply, and transmission failures prevented operating plants from delivering electricity when it was needed most.

Energy Undersecretary Mario Marasigan told Asian Power that electricity prices are affected by conditions across the power system rather than by a single factor.

“Electricity prices are influenced by multiple parts of the power system, including generation, transmission, and reserve requirements,” he said.

He added that delays in either power generation or transmission projects could increase costs because both must be completed on roughly the same schedule.

“If power plants are delayed whilst transmission projects are completed on time, there’s a mismatch,” Marasigan said.

“The same happens if transmission projects are delayed while power plants are ready.

Either way, it will cost us,” the undersecretary continued.

ASIAN POWER 11

INTERVIEW

PGE builds plant data into geothermal design The operator uses field data to improve longterm performance.

B

INDONESIA

efore Lumut Balai Unit 3 starts operating in 2030, Pertamina Geothermal Energy is already using failure records, outage patterns, and maintenance data from its existing plants to shape how the 55-megawatt facility is built.

“A baseload geothermal plant cannot be designed only to achieve commercial operation date,” Andi Joko Nugroho, operations director at PGE, told Asian Power.

Instead of treating the project as a standalone development, PGE is using data from its existing geothermal fields on equipment performance, outage patterns, maintenance schedules, and operational risks to guide engineering decisions.

The information is analysed through a reliability, availability, and maintainability assessment that balances long-term performance against capital costs.

The data influences decisions ranging from equipment selection and maintenance access to spare part planning, inspection schedules, and monitoring systems, the operations director told the magazine.

The plant is also being designed with condition monitoring, predictive maintenance, digital asset management, and enhanced diagnostics from the outset.

A computerised maintenance management system and preventive maintenance programme will be established during commissioning, allowing major inspections, turbine overhauls, steamfield maintenance, and coordination with state utility Perusahaan Listrik Negara to be planned before commercial operations begin.

Spare part inventory will also be based on the importance of each component rather than cost alone. Nugroho said Unit 3 would draw directly on maintenance practices, inventory planning, and equipment failure records from PGE’s existing Lumut Balai units.

Reliability challenges The company is maintaining a stable geothermal resource, ensuring plant equipment can withstand corrosive fluids and mineral scaling, and coordinating operations with the electricity grid. Nugroho described reliability at Lumut Balai Unit 3 as spanning three layers: resource reliability, covering steam supply, reservoir pressure, reinjection performance, and geochemistry; plant reliability, through equipment and materials suited to corrosive fluids and high utilisation; and grid reliability, aligning with PLN's dispatch and outage-coordination requirements.

Spare parts are being categorised by equipment criticality into operational, maintenance, and insurance spares, with insurance spares reserved for long-lead, highimpact components. The company is also developing a reliability-centred spare-parts system to base stocking decisions on failure impact, lead time, and recovery needs 12 ASIAN POWER

A baseload geothermal plant cannot be designed only to achieve commercial operation date

rather than inventory cost alone.

To reduce mean time to recovery, the strategy pairs spare parts availability with dedicated tools, trained manpower, defined emergency procurement routes, and repair-and-return arrangements, alongside preventive and predictive maintenance to catch early-stage degradation before it causes unplanned outages.

Although key technologies such as turbine generators, reservoir modelling, drilling systems, and corrosion management still depend heavily on international suppliers, PGE is using the project to transfer knowledge to local engineers.

Staff participate in design reviews, hazard studies, factory testing, site acceptance tests, and commissioning alongside overseas vendors.

Performance will be measured using several indicators rather than a single target, including plant availability, unplanned shutdowns, capacity factor, reservoir performance, steam quality, and lifecycle costs.

Nugroho said the approach is already delivering results.

In the first quarter of 2026, electricity production rose 15.2% year on year to 1,370 gigawatt-hours, whilst the capacity factor increased to 90.77% and the availability factor improved to 99.63%.

Joko Sutopo, president director at Sulzer Services Southeast Asia—the regional arm of the Swiss-based rotating equipment maintenance and repair group—said corrosion, scaling, and erosion are amongst the biggest reliability challenges for Indonesia’s geothermal fleet as plants operate continuously.

He said Sulzer has introduced specialised materials and repair techniques to extend equipment life, whilst local repair, reverse engineering, and remanufacturing capabilities help reduce outage times by reducing reliance on overseas support and replacement parts.

Andi Joko Nugroho, operations director at Pertamina Geothermal Energy

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ASIAN POWER 13

CO-PUBLISHED CORPORATE PROFILE

Beyond efficiency: Operational flexibility powers future of power generation More than high efficiency, modern power systems require gas turbines that respond quickly to changing grid conditions.

Federico Bonzani, Chief Technology Officer at Ansaldo Energia

A

s gas-fired power plants are now called upon to respond to fluctuating renewable energy generation, operational flexibility has elevated to the same level of importance as efficiency. For power producers, the ability to start quickly, operate at low loads, and respond rapidly to changing grid conditions has become essential to maintaining reliability whilst capturing commercial opportunities in dynamic electricity markets.

As pointed out by Federico Bonzani, Chief Technology Officer at Ansaldo Energia, in an interview with Asian Power, the changing nature of power systems is redefining what operators expect from modern gas turbines.

“Efficiency is still very important, but is no longer enough on its own,” he said. “A modern power plant must be able to start quickly, ramp up and down, operate at low load, and support the grid demand. In that sense, flexibility is not just an additional feature of power generation; we may call it one of the key enablers of a reliable energy transition.”

Renewable-powered grid Ansaldo Energia developed its GT36 H-Class gas turbine with these evolving operating requirements in mind. GT36 is engineered to maintain strong performance well beyond full-load operation, delivering more than 62% combined-cycle efficiency and over 800 MW of output in combined-cycle configuration.

This technology does not focus solely on peak efficiency. It supports grids where renewable output changes throughout the day to allow operators to respond to demand fluctuations.

“GT36 is not a machine designed to run only efficiently at full load,” Bonzani explained. “It has been designed to follow the needs of the grid.”

One of GT36's defining technologies is its sequential combustion system, a feature unique to Ansaldo Energia. By staging 14 ASIAN POWER

combustion across two combustion chambers, the system enables the turbine to maintain stable operation and emissions compliance.

The technology allows the turbine to adapt to different natural gas compositions as well, including varying LNG blends commonly used in Asia. Furthermore, it supports hydrogen blending of up to 70% by volume and provides additional flexibility for future decarbonisation pathways.

Operational flexibility has already become an economic advantage. Electricity markets increasingly reward assets that can respond rapidly to changing system conditions. Faster start-up and ramp-up capabilities allow operators to dispatch power precisely when needed, particularly during periods when renewable generation declines unexpectedly.

GT36 delivers ramp rates of up to 100 MW per minute, which makes the plant capable of reaching full load in less than 15 minutes under proven operating conditions.

“The fast start and high ramping capability of GT36 are not only an engineering achievement, but they also directly improve the way the plant can be dispatched and then monetised in today's electricity markets,” Bonzani said.

Equally important is the turbine's ability to remain online at very low output levels. As renewable generation rises during daylight hours, gas turbines operate in standby mode, ready to increase output as solar production declines later in the day.

GT36 addresses this challenge with its high part-load efficiency and an exceptionally low minimum environmental load of around 15%. This avoids unnecessary shutdowns and restarts, allowing operators to reduce fuel consumption and minimise mechanical wear, whilst maintaining operational readiness and maximising value in increasingly dynamic electricity markets.

Asia's evolving power systems Bonzani believes technologies such as GT36

will become increasingly important as countries seek to integrate larger shares of renewable energy without compromising system reliability.

“The challenge is not only to add more and more renewables. We are talking about renewable integration into the existing system,” he said. “Flexible gas turbines can provide power when it is needed, support the grid during fast changes and enable a high share of renewables.”

Ansaldo Energia complements GT36 and the rest of its gas turbine portfolio with digital solutions such as Integrated Plant Support (IPS) that uses advanced monitoring and diagnostics and enables predictive maintenance. In addition to this, the company offers Plant Integrator, a platform that automatically optimises hybrid plant performance through software and hardware integration.

GT36's operating fleet also demonstrates flexibility and reliability, with five units currently in operation. Collectively, these units have recently surpassed 80,000 Equivalent Operating Hours (EOH), marking a significant milestone for Ansaldo Energia's flagship H-class technology and highlighting its maturity and proven operational performance. Additional units have already been reserved for projects in Europe, and discussions continue across Europe, the Middle East, and Asia.

The dynamic transformation of electricity systems is pushing the industry's priorities to evolve. High efficiency remains essential, but it is no longer sufficient on its own.

“Combining utility-scale output, world-class efficiency and operational flexibility, GT36 is designed to support power systems as they integrate growing shares of renewable energy whilst maintaining reliability, security of supply and grid stability.”

To know more about Ansaldo Energia and its GT36 H-class gas turbine, visit https:// www.ansaldoenergia.com/.

GT36

GT36

GT36 has been designed to follow the needs of the grid

ASIAN POWER 15

R&D PROJECT OF THE YEAR - SAUDI ARABIA

Saudi Energy leads global innovation with cryogenic carbon capture technology

The company advances climate resilience with pilot cryogenic carbon capture, removing multiple plant emissions streams.

Cryogenic carbon capture technology

S

audi Energy (SE) has launched the world’s first-of-its-kind pilot project utilising cryogenic carbon capture (CCC) technology — a system designed to reduce emissions from power plants.

SE developed cryogenic carbon capture technology in collaboration with King Abdullah University of Science and Technology (KAUST) and under the supervision of the Ministry of Energy.

This innovative approach uses freezing techniques to isolate and remove harmful pollutants, including carbon dioxide (CO2), sulfur oxides (SOx), nitrogen oxides (NOx), and particulate matter from the plant’s exhaust stream.

16 ASIAN POWER

Unlike conventional carbon capture methods, CCC offers high-efficiency pollutant separation through ultralow temperature processing; scalable deployment for both mobile and stationary platforms; recovery of valuable byproducts, supporting circular carbon economy goals; Easy retrofitting; and relatively low power and water consumption.

The pilot (CCC) system demonstrated its capability to capture up to a quarter tonne of CO2 per day, positioning it as a practical model for future deployment across the Kingdom’s energy infrastructure.

During real flue gas injection, the CCC system achieved CO2 capture efficiency exceeding 95%. Despite the presence of oxygen in the gas stream, the system operated well below the Lower Explosive Limit (LEL) of the freezing fluid, thanks

to cryogenic temperatures and positivepressure operation, thereby eliminating the risk of explosion.

By integrating the functionalities of Flue Gas Desulfurization (FGD) and Selective Catalytic Reduction (SCR) into a unified cryogenic platform, the system delivers substantial CAPEX and OPEX savings whilst streamlining post-combustion treatment.

Engineered for minimal disruption to live power plant operations and aligned with industry best practices, the system also enables water recovery from gas streams with minimal operational water input.

Importantly, this pilot research project marked a critical milestone in the development of a scaled-up 30-tonne/ day CCC system, serving as a foundational step toward realising SE’s broader decarbonisation roadmap.

SE is positioning itself as a global leader in sustainable energy innovations

ASIAN POWER 17

INTERVIEW

Towngas takes hydrogen to sites, data centres

Cost and regulation remain hurdles to wider adoption of the clean fuel.

HONG KONG

C

onstruction sites in Hong Kong often fall back on diesel generators when grid connections are delayed or insufficient, creating an opening for hydrogen where temporary but high-output power is needed, according to Lawrence Iu, executive director at think tank Civic Exchange.

Hong Kong and China Gas Company Ltd. (Towngas) is targeting these sites, alongside data centres and other facilities with demanding reliability requirements, as it moves hydrogen from pilot testing towards early-stage deployment.

“Over the next one to two years, we are focused on moving from pilot testing to early-stage scaling,” Sammy Kong Siu-kuen, general manager for commercial and industrial marketing and sales at Towngas, told Asian Power.

The company launched Hong Kong’s first hydrogenpowered charging system for a commercial building at its North Point headquarters in April 2026, supplying zerocarbon electricity for electric vehicle charging.

Kong said Towngas is prioritising applications where grid limitations or reliability requirements create immediate demand for alternative power sources.

“These include construction sites with limited grid capacity, commercial operators, and critical-use facilities such as data centres,” he said in an exclusive interview.

Iu said hydrogen systems also let developers and operators test energy demand patterns before committing to permanent grid upgrades, which can be costly and time-consuming.

Alternative solutions Hong Kong has begun expanding hydrogen trials under its hydrogen strategy released in June 2024 that sets out marketled pilots, technical standards, and adoption pathways.

As of end-May, an inter-departmental working group had approved 38 hydrogen pilot projects covering transport, construction equipment, and generator applications.

Kong said the early projects are also expected to generate operating data needed to validate hydrogen systems under Hong Kong’s dense urban conditions.

“A strong safety track record will build confidence amongst regulators and customers,” he added.

Iu said in an exclusive interview that Towngas’ pilot could also support Hong Kong’s efforts to expand electric vehicle charging infrastructure in a city constrained by limited land availability and ageing building stock.

“If we want to fully electrify our commercial fleets, we still need to consider alternative solutions,” he said, adding that providing charging infrastructure for more than 800,000 vehicles would be difficult.

He pointed out that hydrogen could support such fleets as refuelling takes up to 10 minutes and can allow vehicles to travel about 400 to 500 kilometres.

18 ASIAN POWER

Sammy Kong Siu-kuen, general manager for commercial and industrial marketing and sales at Towngas

Over the next one to two years, we are focused on moving from pilot testing to early-stage scaling

“Fuel cell systems may also be easier to repair than batteries because the stack can be replaced relatively quickly,” he added.

Hong Kong’s existing gas network may also support hydrogen adoption, as it already reaches more than 90% of the population and carries a blended gas mix containing as much as 55% hydrogen.

However, analysts said regulatory clarity remains essential for scaling up deployment. Kong said more detailed rules on hydrogen import, storage, transport, and usage are expected to be submitted to the Legislative Council in the fourth quarter for vetting.

In a separate statement, Towngas also called for faster approvals for hydrogen projects and the creation of a dedicated energy office as Hong Kong aligns its development plans with mainland China’s 15th Five-Year Plan.

The group backed a proposal to set a two-month target for the Inter-departmental Working Group on Using Hydrogen as Fuel to decide on pilot applications.

Cost is another constraint on wider adoption.

Iu said shipping accounts for about 20% to 30% of Hong Kong’s retail hydrogen price, whilst current shipment sizes of 400 to 700 kilos remain too small to achieve scale efficiency. Bigger shipments in the range of several tonnes could reduce transport costs.

Officials are exploring options to lower import costs, with agencies including the Electrical and Mechanical Services Department and the Environment and Ecology Bureau reviewing supply and procurement frameworks.

Kong said Towngas could supply about 34 tonnes of hydrogen per day, which he said is sufficient for early and medium-scale projects in Hong Kong.

“By using town gas as a carrier for hydrogen transport and extraction, we avoid the massive upfront capital expenditure required for new production infrastructure,” he added.

ASIAN POWER 19

MARKET REPORT: INDONESIA

Indonesia sets 2032 target for first nuclear power plant Nuclear is now embedded in Indonesia’s long-term energy mix.

I

ndonesia has moved nuclear power from decades of stopstart exploration into its formal energy strategy, setting 2032 for its first reactor and shifting the question from whether to pursue the technology to whether the country’s power system is ready for it.

The government’s roadmap outlines 45 gigawatts (GW) of nuclear capacity through 2060.

It allocates 35 GW for electricity and 9 GW for hydrogen, with the first 250-megawatt (MW) unit expected to start operating in 2032, followed by another plant of similar size.

Alongside generation planning, the government is starting to build the institutions needed for a nuclear programme. It has created an agency to manage uranium, thorium and other strategic minerals, bringing fuel-supply considerations into the same long-term planning framework as reactor development, grid integration and regulation.

PT Perusahaan Listrik Negara

Didik Fauzi Dakhlan

Tony Susandy

The government’s plan allocates 35 GW for electricity and 9 GW for hydrogen

20 ASIAN POWER

(Persero), the state-owned power generator and distributor, is assessing whether nuclear power can be safely integrated into the electricity system, with grid readiness emerging as a key consideration alongside the technology itself.

“When we talk about nuclear, there are many variables that must be considered,” Didik Fauzi Dakhlan, PLN’s executive vice president of asset management, engineering and integration management system, told Asian Power in an interview.

“This is not simply about choosing technology, but ensuring that our system is strong and ready to accommodate it.”

Why nuclear now Nuclear power could provide steady, low-emission generation as Indonesia adds more intermittent renewable energy.

Electricity demand is expected to reach 1,813 terawatt-hours by 2060, requiring 443 GW of net-

capable capacity. Renewables are projected to supply 42% of output, backed by 34 gigawatts of storage, a structure that officials say will still require firm baseload generation to maintain reliability.

“This is no longer optional,” Tony Susandy, a senior official at the Ministry of Energy and Mineral Resources, told a forum in Jakarta.

“Nuclear is becoming one of the tools that will balance Indonesia’s energy mix and support our netzero pathway,” he continued.

The National Research and Innovation Agency has said Indonesia must deliver at least 500 MW of nuclear capacity by 2032.

PLN also added nuclear power to its official generation outlook for the first time in 2025, including a 250MW plant for Sumatra in 2032 and another for Kalimantan in 2033.

Renewables, storage and nuclear account for 76% of its planned capacity additions.

Grid limits How quickly nuclear can scale will depend partly on the strength of Indonesia’s regional grids.

Didik said the 250-MW reactor size being studied reflects conditions in Sumatra and Kalimantan, where grid strength is about 300 MW per hertz.

Larger plants could create instability in those systems.

Indonesia’s power network is also divided across separate island systems. Java-Madura-Bali has the country’s largest and strongest grid, whilst Sumatra and Kalimantan operate independently. For now, Java-Madura-Bali is the only system capable of accommodating very large nuclear plants, whilst bigger reactors in Sumatra or Kalimantan would require stronger interconnections with Java.

Technical readiness is only part of the challenge. Didik said policy and institutional arrangements must also be established before nuclear development can accelerate.

“What is most urgent now is a presidential regulation to speed up nuclear development and the creation of a dedicated nuclear body, because nuclear power is as much about geopolitics and public acceptance as it is about technology,” he said.

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ASIAN POWER 21

MARKET REPORT: SINGAPORE

Carbon tax clarifies costs, risks widen Narrowly focusing on the tax overlooks the full economic picture.

F

SINGAPORE

or a company weighing gas against imported green power in Singapore, the carbon tax is only one line in the calculation.

Grid charges, backup power, foreign exchange exposure and unresolved regulations could ultimately determine which option costs less.

“Executives often focus narrowly on the carbon tax as the deciding cost factor, but this overlooks the full economic picture,” Mark Addy, partner, Energy & Natural Resources and Telecommunications, Media & Technology, Tax, KPMG in Singapore, told Asian Power.

Whilst renewable energy can lower operating costs over time, upfront spending on development, installation, and grid integration remains high.

Costs are even steeper in hard-toabate sectors, where carbon capture can exceed prevailing carbon tax levels.

Singapore’s Budget 2026 projects the carbon tax could stabilise near $38.99 (S$50) per tonne of carbon dioxide by 2030, giving firms a clearer planning benchmark. Gas, meanwhile, faces pressure at carbon prices of $38.99 to $62.39 (S$80) per tonne but remains competitive.

“Modern combined-cycle gas turbine plants have achieved significant efficiency gains,” Addy said in an exclusive interview, citing improved output per unit of fuel.

Reliability issues Lim Wen Bin, partner, Infrastructure Advisory, KPMG in Singapore, said such gains could offset roughly $1.56 (S$2) to $2.34 (S$3) per megawatt-hour at a carbon tax of about $45 per tonne, though most savings stem from fuel efficiency rather than emissions cuts.

Beyond fuel and carbon, companies weighing green imports must factor in foreign exchange exposure, counterparty credit risk, balancing charges, backup power costs, and potential supply disruptions, he said.

Reliability issues can raise emergency procurement costs and delay operations. Regulatory uncertainty also remains a key concern.

“The most material risks sit in the gaps policymakers have not yet closed,” 22 ASIAN POWER

Carbon tax could stabilise near $38.99 per tonne of carbon dioxide by 2030

Mark Addy

Lim Wen Bin

Maria Tan Pedersen

Maria Tan Pedersen, a partner at Dechert LLP, told the magazine.

A regional framework for crossborder renewable energy certificates being developed by Singapore agencies and the I-TRACK Foundation is still incomplete, raising the risk of overlapping claims on the same unit of green power, she said.

Disclosure rules add another layer.

Singapore’s environmental, social, and governance reporting regime requires continuous verification of supplier certifications, whilst firms with European exposure must comply with stricter climate reporting standards.

Financing conditions are also shifting. Local lenders such as DBS Bank Ltd., Oversea-Chinese Banking Corp. Ltd., and United Overseas Bank Ltd. increasingly require transition plans for gas-related projects, Pedersen said.

Singapore has signed conditional import deals with Cambodia, Indonesia, and Australia to meet its 6 gigawatts target.

Lim said companies should also track the cost of renewable energy in exporting markets, international liquefied natural gas prices, firming-

power costs such as battery storage, the availability of subsea highvoltage direct current infrastructure, and regulatory stability for crossborder power trade.

Separately, grid access charges for Singapore’s planned subsea import corridors from Indonesia, Malaysia and Australia have also yet to be settled, adding another unresolved cost variable, Pedersen said.

She said network charges account for roughly 30% of total delivered electricity costs in the UK, but Singapore’s equivalent figure remains undetermined, leaving a significant variable out of current financial models. Pedersen said no equivalent government commitment exists for additional gas import capacity.

As renewable costs fall and renewable energy certificate premiums narrow, Lim said green imports could emerge as both a cost-saving and risk management strategy.

“When renewable energy certificate premiums fall alongside stable renewable supply chains, companies benefit from both lower effective costs and enhanced sustainability performance,” he added.

ASIAN POWER 23

ANALYSIS: ENVIRONMENT

El Niño events typically last six months to just over a year, with peak strength in late 2026

Super El Niño may test Asian power grids in waves

Hydropower losses could give way to heat-driven demand as pressure shifts across markets.

APAC

A

sia’s next power crunch may not arrive everywhere at once. A potential Super El Niño could first squeeze hydropower supply in Southeast Asia in late 2026, then shift pressure to heat-driven electricity demand across other markets into the first half of 2027.

Eldon Lopes, research manager for meteorology at Wood Mackenzie Ltd., said the weather event is already matching the intensity of spring 2015 despite starting later in the year. It is expected to surpass the 2015-2016 and 1997-1998 events to become the strongest El Niño on record, he added.

Yi Ming, a professor at the Department of Earth and Environmental Sciences of Boston College, expects sea temperatures in the eastern Pacific to reach about 3.5 degrees Celsius above normal

by October 2026.

“That makes the current El Niño officially a super El Niño because the definition is above 2.5 degrees Celsius,” he told Asian Power. “The expectation right now is that this will set a new record.”

Nikhil Babu, a research analyst for power and renewables at Wood Mackenzie, said the impact would be 24 ASIAN POWER

The impact would be a rotating sequence of tighter power systems across Asia, rather than a single regionwide peak

“a rotating sequence of tighter power systems across Asia, rather than a single region-wide peak.”

El Niño events typically last six months to just over a year, Lopes said. Peak strength is expected from late 2026 to early winter 2026-2027, with Asian markets taking the brunt of the impact from the fourth quarter of 2026 through the second quarter of 2027.

Timing will be a key risk because power demand peaks at different times across Asian markets, Babu said.

India and Thailand have passed their spring demand peaks, whilst China is expected to reach 1,575 to 1,600 gigawatts (GW) of peak demand between July and September. Japan, South Korea, and Taiwan are expected to peak in August, whilst Vietnam’s peak demand is about 58 GW. Australia and New Zealand face a later risk between December and February, when summer demand coincides with potentially stronger El Niño conditions, Babu said.

The first major supply shock could emerge in the fourth quarter as warmer eastern Pacific waters cause drier conditions across Southeast Asia and reduce hydropower

availability, Ming said.

A second wave could follow about a month later as the effects shift from the supply side to electricity demand. A positive Indian Ocean Dipole could intensify the drying effect by drawing rainfall away from Southeast Asia, he added.

“Precipitation normally just follows the warm ocean,” Ming said.

Hotter conditions could also constrain thermal generation if cooling water becomes too warm to operate power plants effectively.

Operators could then be forced to reduce output or shut units, creating a supply constraint separate from fuel availability and hydropower levels.

Dinita Setyawati, a senior energy analyst for Asia at Ember Energy Research CIC, said disaster risk reduction and energy planning should be incorporated into powersector planning.

Measures could include securing rooftop solar installations, making wind farms resistant to water and flooding, and developing smarter and more automated grids, she said.

Utilities should also integrate high-frequency weather forecasts into planning, Setyawati said.

Vietnam, for example, could use battery storage to preserve solar power and offset weaker hydropower output, whilst the Philippines and Singapore have developed advanced forecasting and grid command systems.

Consumers to bear cost Setyawati said distributed renewable generation could improve resilience because disruptions are less likely to affect an entire power system.

India’s record demand is less likely to threaten reliability because more than 65% of its electricity demand is being met by coal, Babu said.

Weaker hydropower would therefore mainly increase coal use.

China faces greater hydropower risk if weaker inflows coincide with high east-coast demand, whilst Vietnam could see record demand during a weaker hydropower season.

Japan, South Korea, and Taiwan face heat-driven demand during their August peaks, with tighter reserve margins making them more sensitive to renewable and hydropower shortfalls.

ASIAN POWER 25

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OPINION

Scaling for resilience: What APAC's bioenergy markets can learn from each other

E

nergy security has returned to the centre of energy policy across Asia-Pacific. Recent geopolitical tensions, including disruptions around the Strait of Hormuz, have reinforced a critical lesson for energy-importing economies: Resilience cannot rely solely on global fuel markets, shipping flexibility, or strategic reserves.

Countries are looking for ways to anchor parts of their energy systems closer to home. This is where bioenergy is gaining renewed strategic relevance. It offers something that solar and wind cannot easily provide: Dispatchable, storable fuels derived from domestic or regional resources.

Biodiesel, ethanol, biogas and biomethane can reduce exposure to imported fuels whilst making productive use of agricultural and waste streams already present within economies.

However, progress across Asia-Pacific is not uniform. It is a patchwork of national approaches, shaped by local resources, policy choices, and infrastructure constraints. Together, these experiences show that the next phase of bioenergy growth will depend on crosscountry learning and scaling what already works.

Biofuels: The importance of policy discipline Indonesia provides the clearest example of large-scale bioenergy deployment aligned with national energy security goals. Its B40 biodiesel mandate is one of the most ambitious in the world, aimed at reducing diesel imports and retaining more energy value domestically. The programme demonstrates that with strong policy support, established supply chains, and a clear strategic objective, biodiesel can scale rapidly.

Indonesia also highlights the limits of this approach. Moving towards higher blends such as B50 requires sustained feedstock availability, expanded production capacity and continued fiscal support. It also raises scrutiny over land use and sustainability. The lesson is not that biodiesel cannot scale further, but that scale must be matched by careful management of feedstock, cost, and public trust.

Malaysia’s more cautious approach illustrates this point. Whilst it has significant palm oil resources, it has limited nationwide biodiesel blending to B10, with B20 deployed selectively. The constraint is not ambition, but infrastructure readiness and exposure to volatile crude palm oil prices. Malaysia shows that technical feasibility must be matched by logistics, market design, and price stability.

For the Philippines, the challenge is different again. Reliance on coconut oil for biodiesel has constrained expansion beyond B3 due to competing uses in food and export markets. This underscores a broader lesson: Feedstock diversity matters. Overreliance on a single agricultural commodity introduces structural limits to scaling.

Vietnam presents a similar opportunity. Under new regulation, nationwide E10 gasoline becomes mandatory from June 2026, with E15 to follow from 1 January 2031. The policy is underpinned by domestic cassava-based ethanol production and six fuel-ethanol plants, equivalent to roughly 40% of projected E10 demand.

Whilst biodiesel has been the most visible part of the bioenergy story, the next phase is increasingly centred on biomethane and renewable gas.

30 ASIAN POWER

DR. REZA YOSRI APAC Biogas and Biomethane Lead Ramboll

Malaysia’s biomethane initiative offers a glimpse of this shift.

A centralised injection facility in Johor, aggregating biogas from surrounding palm oil mills and feeding it into the gas grid, represents a significant step forward. It moves bioenergy beyond on-site power generation towards integration with existing infrastructure, unlocking higher-value uses in industry and gas markets.

Indonesia is also moving in this direction, faster than its biodieseldominated profile suggests. PGN has signed an agreement to supply POME-derived biomethane to NeutraDC’s data centre projects in Singapore from 2027, drawing on infrastructure in West Java. In parallel, Pertamina and Singapore LNG Corporation are developing a Bio-LNG value chain that converts POME into Bio-LNG for Singapore. Both projects show Indonesia’s POME resource being upgraded into renewable gas and Bio-LNG, with cross-border offtake into a premium market acting as the catalyst.

Thailand is already further along this pathway. With a mature base of biogas projects from cassava, livestock, and food-processing waste, the challenge is no longer proving the technology. It is about upgrading and redirecting these flows into higher-value applications, such as transport fuels, industrial gas, or grid injection. This requires standards, incentives, and clear offtake markets.

Market creators: The role of demand centres Not all countries contribute to bioenergy supply. Some will shape the market through demand.

Singapore is a case in point. With limited domestic feedstock, its role is to test market frameworks, such as its biomethane sandbox, where renewable gas can be imported, certified, and used within existing infrastructure. A credible demand signal from Singapore could support project development across feedstock-rich regional markets.

Japan plays a similar, but larger, role. Its interest in biomethane, Bio-LNG and e-methane reflects a strategy built around existing LNG infrastructure whilst diversifying supply sources. For regional producers, Japan represents a potential premium market, but one that requires high standards of certification, traceability and sustainability.

Together, these markets highlight a key dynamic: Bioenergy scale will not be achieved by supply alone. It requires credible, long-term demand signals.

Scaling what works: A regional learning agenda Taken together, these country experiences suggest that the challenge is not a lack of technology, but a lack of scale and integration.

Several priorities stand out: Diversifying feedstocks, building aggregation models, creating stable policy frameworks, developing offtake markets, and strengthening certification and traceability.

Most importantly, there is a need for regional learning. Indonesia’s scale, Malaysia’s infrastructure integration, Thailand’s project maturity, and Singapore and Japan’s demand frameworks each represent pieces of a broader system. No single country has all the answers, but collectively, they offer a blueprint.

ASIAN POWER 31

OPINION

Why bigger digesters alone won’t solve Asia’s renewable energy challenge DR. SYAZWANI IDRUS Associate Professor Universiti Putra Malaysia

A

cross Malaysia, China, Singapore, the Philippines, Thailand, and Indonesia, governments and energy producers are aggressively positioning organic waste as the cornerstone of the region’s renewable energy transition.

Yet, a fundamental misconception threatens the commercial viability of these multi-million-dollar assets. For too long, success in anaerobic digestion (AD) has been measured by the wrong metrics: The sheer volume of waste processed and the gross amount of biogas generated.

For energy executives and project developers across Asia, the hard truth is this: Abundance does not equal efficiency.

Building larger digesters alone will not yield profitability if systems remain plagued by biological instability, poor feedstock management, and archaic purification methods.

The next phase of market leadership will not belong to those who process the most raw mass, but to those who master the conversion of complex, volatile waste streams into high-yield, grid-ready energy.

Unlocking the regional chemistry of volatile feedstocks The operational realities of Asia demand a radical departure from Western, single-source AD models.

The region's rapid urbanisation, expanding livestock markets, and intensive agricultural industries present a highly volatile mix of localised feedstocks. Recent performance monitoring reveals exactly where mono-digestion fails based on geographic feedstock dominance and how smart integration bridges the gap.

The souring threat of urban food waste In the highly urbanised commercial centres of Singapore and Malaysia, increasing volumes of food waste represent an extraordinary bioenergy asset due to high volatile solids.

However, its raw composition is a ticking financial time bomb for operators: It is inherently highly acidic and possesses an extremely skewed carbon-to-nitrogen ratio. In continuous digester operations, pushing organic loading rates past standard limits triggers immediate system shock, causing rapid volatile fatty acid accumulation and structural digester failure.

The ammonia bottlenecks in mass livestock production Across the major livestock-producing economies of Thailand, Vietnam, and China, animal manure provides massive volume but introduces severe biochemical roadblocks.

Pure animal dung suffers from a low carbon-to-nitrogen ratio due to concentrated uric acid and undigested proteins. Mono-digestion of this material generates high concentrations of ammonia, which rapidly leads to free ammonia inhibition and severe microbial toxicity, rendering high-rate systems commercially unstable.

Simultaneously, the massive agricultural economies of China, Thailand, Vietnam, and the Philippines generate substantial quantities of crop residues, including rice straw, corn stover, and sugarcane waste.

Whilst these materials offer valuable carbon potential, their high lignin 32 ASIAN POWER

content limits natural biodegradability and creates a severe structural bottleneck to efficient methane conversion. To break through this degradability wall and unlock successful energy recovery, operators cannot rely on raw abundance alone.

Success requires mandating advanced chemical or thermal pretreatment to break down the resilient lignin matrix, paired with strategic co-digestion alongside high-sugar industrial wastes such as molasses residues or crude glycerol to balance the carbon profile and dramatically accelerate microbial digestion rates.

The efficiency gap: A wake-up call for operators The most glaring vulnerability in Asia’s current AD landscape lies in post-digestion processing. Producing biogas is entirely meaningless if the majority of that energy is lost before it ever reaches the grid or an industrial buyer. Consider a sobering benchmark from a recent operational analysis of a large-scale slaughterhouse wastewater AD facility: Significant energy losses can occur between digestion, purification, and final electricity generation.

In one slaughterhouse wastewater digestion facility, an estimated energy potential of 790kWh resulted in only 260kWh of electricity output, demonstrating the substantial gap between available energy resources and actual energy delivered.

This reinforces the need for improved biogas purification technologies and more efficient combined heat and power (CHP) systems.

This massive leakage is primarily driven by subpar biogas upgrading and purification systems. Raw biogas in Southeast Asia is heavily contaminated with ammonia gas, carbon dioxide (CO2) and volatile organic compounds (VOCs). When operators skimp on advanced purification technologies, these contaminants rapidly corrode downstream Combined Heat and Power (CHP) engines, skyrocketing maintenance overhead and forcing frequent, costly shutdowns.

Moving from a controlled environment to an operational, revenue-generating asset reveals the true scope of Asia’s conversion gap. Semicontinuous piloting across food waste, animal waste, sludge from water and wastewater treatment facilities, as well as industrial wastewater feedstocks, exposes a sobering benchmark for plant economics: approximately 67% of the total energy potential is lost during the treatment, upgrading, and thermal conversion processes.

Generating raw biogas is entirely meaningless if the final, net electricity delivered to the generator remains heavily restricted by system inefficiencies. If Asian energy producers are to protect their margins on an increasingly competitive modern grid, they must pivot from a mindset of simple waste processing to optimising the waste-to-energy value chain.

This requires three immediate strategic mandates.

Future infrastructure projects must move away from isolated, single-substrate facilities and look towards localised hubs explicitly engineered to blend urban organic fractions, high-nitrogen poultry dungs, and industrial wastewaters to maximise chemical stabilisation.

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