This is not an argument that existing coal transition frameworks are wrong in principle. The Energy Transition Mechanism, the transition credit methodologies developed through Verra and Gold Standard, the JETP processes in Vietnam, Indonesia, and the Philippines: these represent years of serious, well-intentioned work by organizations that seek a solution to a problem.
The question we want to raise, carefully, is whether the framework these efforts share is actually suited to the market conditions they are trying to operate in. Because the results, so far, are thin. Announced transactions have stalled or been revised. Plants initially flagged for retirement have been reclassified as captive power facilities, still burning coal, just removed from the public accounting of the transition. The gap between commitment and verified outcome is wide and not narrowing fast.
We think that gap is structural. And we think understanding it is more useful than simply trying harder within the same framework.
The binary problem
Every major coal transition framework operating in Southeast Asia right now is built around the same core logic: a coal plant retires early, a renewable replacement is built, and the difference in lifetime emissions becomes a carbon credit that finances the transaction.
That logic requires the retirement to be binary. The plant is either closed or it is not. There is no credit for running at 40% of contracted capacity instead of 90%. There is no reward for displacing three million tonnes of emissions over five years while maintaining grid stability and operator employment. The methodology requires a permanent shutdown, and only then does the crediting event occur.
This creates an immediate mismatch with how power systems in this region actually function. Grid operators cannot switch off baseload coal capacity on a schedule set by a carbon finance transaction. Regulators face real energy security constraints. Operators have assets still recovering capital, workforces expecting continuity, and long-term contracts that were not written to accommodate early termination. So the binary ask, retire now in exchange for a promise of future carbon revenue, runs into resistance that no amount of concessional finance fully resolves.
Transition credits reward the cliff. What this region's power sector actually needs is a mechanism that works on the ramp.
The financing structure compounds this. To make a coal operator whole on early retirement, a buyer must cover the full net present value of the remaining contracted cash flows. For a plant mid-PPA with fifteen years remaining, that is a large number. It has to be committed upfront, years before a single tonne of verified emissions reduction has occurred. The investor is essentially purchasing a promise: the plant will close, the renewables will be built, the credits will be issued. Each of those steps has its own risk, and they compound.
That is not a description of a broken idea. It is a description of a high-risk, capital-intensive transaction that requires a specific set of conditions to close: a willing operator, a government that will authorize retirement, a development finance institution or philanthropic fund willing to absorb the upfront risk, and a carbon buyer willing to commit to future credit purchases at a price that justifies the whole structure. Getting all four aligned, on a single asset, at the same moment, turns out to be very hard.
What the evidence shows
The ADB's Energy Transition Mechanism was announced in 2021 with ambitions to accelerate coal retirement across the Philippines, Indonesia, and Thailand. Several years in, closed transactions that have produced verified emissions reductions remain rare. The pilot transactions that have progressed have done so slowly, and in some cases the definition of what counts as a successful outcome has shifted as the practical obstacles accumulated.
The JETP processes, which attracted headline pledges of $20 billion for Indonesia and comparable sums for Vietnam and the Philippines, have moved from announcement to implementation more slowly than expected. Disbursement has lagged. The coal plants that were intended to anchor early phases of these programs remain operational on roughly their original schedules.
Some of the assets initially targeted for retirement have been reclassified. A plant that moves from grid-connected IPP to dedicated captive power supply for an industrial customer is technically no longer part of the public generation mix. It is still burning coal. The emissions are still occurring. The transition accounting has improved without the underlying physical situation changing.
None of this is a failure of effort. It is a signal that the framework encounters consistent structural resistance in this specific context, and that the resistance is not going away.
A different structure
SPARC starts from a different place. It is not a policy instrument. It is a business proposal: a bilateral commercial arrangement between a coal operator who holds a PPA and a renewable developer who wants contracted revenue. The coal operator does not exit. Nobody asks them to surrender their asset, their workforce, or their grid position. Instead, they transfer a defined slice of their contracted generation band to a renewable operator who fulfills it with cleaner electricity.
The coal operator retains their profit margin and fixed cost recovery under the PPA. The MWh they no longer produce stop costing them: no fuel, no variable operating cost, no delivery risk. That avoided cost is what passes to the renewable developer as the economic basis for their delivery fee. The renewable developer earns that fee for fulfilling the contracted band and may capture additional value through ARCs from the verified emissions displacement. Neither party is being asked to sacrifice something in service of a climate objective they do not fully control. The deal works because value moves, not because one side absorbs a loss.
This matters for a reason that goes beyond individual deal economics. A coal operator in the Philippines or Thailand who participates in SPARC does not become an obstacle to the energy transition. They become part of it, while remaining an energy company. Their fleet gradually greens from within. At the end of the PPA term, a company that has demonstrated a decade of managed transition and maintained reliability may be better placed to negotiate contract renewal than one that simply ran coal at full capacity until the PPA expired. SPARC does not push operators out of the market. It gives them a path to stay in it.
On ex-post versus ex-ante payment. Under existing transition credit frameworks, capital is committed before any emissions reduction has occurred, against a modeled projection of future credits. Under SPARC, ARCs are issued after a specific MWh of renewable generation has been metered and verified against the embedded emission entitlement of the coal PPA band. The buyer receives a receipt for something that already happened, not a promise about something that might.
Gradual, not binary
The practical consequence of working at the MWh level is that the mechanism is inherently gradual. A coal plant does not need to commit to closure to participate. It does not need to find a buyer for its entire remaining cash flow NPV. It needs to agree on a delivery band, identify a renewable counterparty, and sign a SPARC stream agreement for a defined term.
That is a much lower bar. And because the financial logic works on each MWh independently, the arrangement can start small, with one delivery window or one seasonal block, and expand as confidence builds and renewable capacity comes online. The coal operator can adjust their participation without renegotiating the underlying PPA. The commitment is bounded and reversible in a way that a retirement transaction is not.
Over time, as more SPARC streams are established across a plant's contracted output, its load factor declines. It continues to exist as contracted capacity, available for grid reliability, but producing less and less of the generation it was originally designed to supply. At some point, the remaining contracted output is small enough that a conventional retirement transaction, if one is wanted, becomes a much lighter lift. The NPV buyout that was prohibitive at full capacity becomes manageable at minimum stable load.
SPARC does not prevent traditional retirement. It reduces the scale of the problem progressively until the remaining step, whatever form it takes, is smaller and cheaper than it would have been at the outset.
Not better: structurally different
We are not claiming that SPARC is superior to what ETM programs and transition credit projects are attempting. The full-retirement model has genuine advantages in some contexts: it produces a cleaner emissions accounting story, it aligns with certain compliance market requirements, and it delivers a definitive outcome when the conditions are right.
The conditions are right less often than the frameworks require. That is the observation we are making.
The comparison below is not a scorecard. It is an attempt to map where the structural differences sit and what they mean for the kinds of transactions each approach can realistically close.
| Dimension | SPARC / ARC | Transition credits / ETM |
|---|---|---|
| Unit of action | 1 MWh dispatch event | Full plant retirement |
| Capital requirement | No buyout; bilateral commercial deal | NPV buyout of remaining PPA cash flows |
| When capital is committed | Ex-post, after verified dispatch | Ex-ante, years before credits are issued |
| What the buyer purchases | Verified impact, already occurred | A promise of future retirement |
| Additionality basis | Embedded regulatory entitlement vs metered outcome | Counterfactual modeling of would-have-operated baseline |
| Structuring timeline | Months (bilateral agreement) | 3–5 years per transaction |
| Coal operator outcome | Remains an energy company; PPA economics preserved | Exits the market; requires full compensation |
| Reversibility | Gradual, adjustable, bounded by stream term | Binary and irrevocable |
| Scalability constraint | RE cost differential and ARC price | Availability of concessional or philanthropic buyout capital |
| Pathway to full retirement | Optional later step; plant load factor declines progressively | Required precondition for any credit issuance |
The approaches are not mutually exclusive. A coal fleet that has run down its load factor through SPARC over a decade is a much more tractable retirement candidate than one that has been running at full capacity. SPARC can be the first chapter of a transition that ends with a conventional retirement, if that is what the operator, government, and investors ultimately want.
For now, the more pressing question is whether verified emissions reductions can start happening in this region before the political and financial conditions for full retirement arrive. We think they can. The mechanism for doing it already exists in the commercial and contractual structures of the coal PPAs themselves. It just needs to be unlocked.