Coal in Southeast Asia will not flex on command

Summary

In Southeast Asia, coal flexibility is constrained more by contracts, operations and market rules than by engineering limits.

Long-term PPAs and current market arrangements reward steady output and discourage ramping, even where plants are technically capable of more flexible operation.

Operating coal plants more flexibly could help where grids are already congested or under pressure, as more renewables come online. However, in most systems, it makes little difference unless market rules and contracts also change.

What is coal flexibility?

Coal flexibility refers to the ability of coal plants to operate reliably at varying load levels and to respond dynamically to system requirements. Unlike conventional baseload operation — where plants run continuously at or near full capacity — flexible coal units adjust their output in response to fluctuations in grid demand and renewables generation across hours in the day and seasons in the year. For more details, read our introductory blog on this topic, Coal flexibility in Southeast Asia: a stepping stone, not a destination.

Coal flexibility in Southeast Asia

For decades, coal-fired power plants have underpinned electricity supply across Southeast Asia, supporting growing economies with steady output. Market structures and long-term contracts reward reliability, not responsiveness, keeping coal running as baseload. This enabled capacity expansion, but also fixed coal in steady operation, leaving little reason for plants to ramp even where they can.

This settlement is now under pressure. As solar and wind expand, utilities and governments are testing whether coal can operate differently. Indonesia’s Perusahaan Listrik Negara (PLN) is modelling lower annual capacity factors for selected units. Vietnam is running low-load tests at two coal plants to assess constraints and retrofit options. Thailand’s Electricity Generating Authority of Thailand (EGAT) is examining flexibility at the Mae Moh complex. In the Philippines, more permissive contracting allows coal plants to sign multiple PPAs and price output by dispatch role, though most still run as baseload in practice.

These initiatives remain modest, but they reflect growing recognition that coal’s traditional role no longer fits systems that are absorbing more and more variable renewable energy generation. The question is no longer just how much coal capacity to retain, but whether and where that capacity should operate flexibly. It is worth noting at the outset that the binding constraint is not engineering. Under current conditions, flexible coal is rarely the least-cost or least-risk option for plant owners, system operators or consumers.

This second blog in our coal flexibility series examines why coal flexibility remains out of reach in practice, and focuses on the challenges to achieving coal flexibility at three levels: system needs, operational realities and contractual structures.

System needs: does Southeast Asia need coal to flex?

Coal flexibility only makes sense where the power system actually needs it. That need tends to arise where solar and wind already strain the grid – through renewable power being curtailed, transmission bottlenecks, or rapid changes in demand for conventional generation as weather conditions shift. In such cases, generation that can respond quickly helps the system stay balanced. Where renewable penetration remains modest and curtailment is limited, greater coal flexibility has little effect. Coal continues to run as baseload because the system does not yet require frequent balancing from it.

The cause of curtailment also matters. Where it occurs in response to dispatch and cost-order effects – such as when cheaper renewable power is pushed aside by thermal plants – more flexible thermal operation can help. Where it occurs due to physical limits like weak transmission, congestion or limited interconnection, so electricity cannot be moved to where it is needed, coal flexibility is helpful only if a plant sits at the constrained point on the grid and can change output quickly.

Taken together, these conditions make Vietnam and the Philippines relatively more conducive to coal flexibility, with important caveats. In Vietnam, the opportunity is highly location-specific, with the best candidates for flexible generation located mainly in the south. In the Philippines, more flexible contracting is possible, but inefficient plant designs and still-limited renewable penetration limit the benefits. In Indonesia, flexibility may be feasible for a small number of overcapacity units, but its value would probably remain limited as long as grid and renewable build-out lag.

Operational realities: why deeper flexibility is harder than it sounds

In practice, coal output in Southeast Asia already varies across seasons and years. What remains uncommon is the intra-day cycling and frequent ramping that could help balance solar and wind. For example, a large coal plant in Peninsular Malaysia has recorded annual capacity factors ranging from 75% to 86%. This shows that operators can adjust output over time. It does not mean they can ramp up and down several times a day.

At the system level, many grids still rely on limited short-term forecasting, manual dispatch and weak reserve procurement. This means system operators have only a partial view of near-term demand and supply, rely on manual rather than automated controls, and lack standby capacity to respond quickly when conditions change. These will need to change to support flexibility – not only for coal plants, but also for emerging technologies such as batteries. Indonesia’s centrally dispatched system struggles with sub-hourly scheduling across a dispersed fleet, making it difficult to adjust output frequently and safely. In the Philippines, market signals exist, but transmission bottlenecks and limited reserves constrain how much flexibility can be delivered without risking system stability. In Vietnam, dispatch practices are only just beginning to adapt to higher renewable penetration.

At the plant level, most coal units were designed for steady output. Limits in boilers and turbines mean they cannot heat up, cool down or ramp output quickly without stress; older control systems are often not built for frequent adjustment; variable fuel quality can destabilise combustion; and uneven maintenance increases the risk of wear and failure. Without upgrades, more intensive cycling raises the likelihood of outages.

Targeted retrofits can help. These include control-system upgrades, additional instrumentation and revised maintenance regimes. But they are costly. Without compensation mechanisms, they are rarely economic.

Contracts: PPAs force operators to keep coal running as baseload

Coal dispatch in Southeast Asia is driven less by markets than by contracts. Long-term power-purchase agreements determine how plants earn revenue, how risks are allocated and, in practice, how units are dispatched.

PPAs dominate revenues

Most coal plants earn the bulk of their revenue from PPAs rather than energy markets. Where spot markets exist, they do not yet offer better returns than long-term contracts. For instance, in Vietnam, foreign-owned independent power producers (IPPs) have largely stayed out of the pilot wholesale market because their PPAs offer greater revenue certainty. In the Philippines, PPA structures continue to favour steady baseload output.

Long tenors create lock-in

PPAs typically cover 25–30 years, and therefore embed assumptions about how coal plants will operate, often well beyond the point at which debt is repaid. Renegotiating these contracts is legally complex and politically sensitive. This is seen in Indonesia’s Jawa–Bali system, where persistent oversupply has translated into only limited success in revising coal contracts.

Two-part tariffs dull incentives

Most PPAs separate fixed capacity payments from VRE payments. Because capacity payments remain unchanged when output falls, operators have little financial incentive to vary generation. Cycling only increases fuel use, maintenance costs and outage risk, and brings no offsetting reward.

Must-run clauses and fuel commitments

Some PPAs include minimum offtake or must-run provisions that further restrict flexibility. Long-term coal supply contracts often reinforce this rigidity through minimum purchase obligations. As a result, even where a plant is technically able to ramp, contractual terms may prevent it from doing so.

Looking ahead

Coal flexibility in Southeast Asia is not primarily a technical problem. It is a problem of system readiness, risk allocation and contracts.

Where flexibility makes sense in the near term, it should be targeted: limited to specific units and locations facing real congestion or curtailment, or with shorter remaining contract lives. Such cases warrant detailed, plant- and system-level modelling to assess operational limits, costs, risks and system value before pilots are pursued, alongside clear operating parameters and explicit compensation.

Where renewable penetration remains low, curtailment minimal, and PPAs inflexible, coal flexibility is unlikely to change outcomes. In these systems, flexibility is better suited to come from cleaner sources of technologies like batteries.

Recognising these differences is essential. A case-by-case approach, grounded in system modelling rather than assumptions, allows utilities and policymakers to judge where coal flexibility has a role, where alternative options are more effective, and where retirement pathways should be considered as power systems evolve.

This is the second in a three-part series exploring the potential of coal flexibility in Southeast Asia. Part I describes the ins and outs of coal flex, with an eye to Southeast Asia, and Part III will feature a case study simulating coal flexibility in Malaysia.