Green hydrogen should replace grey hydrogen before it reaches a power plant

Over the past three years Lintasari has received more proposals involving hydrogen than involving any other technology. Most arrive as memoranda of understanding: an equipment maker, a prospective buyer in North Asia, a government agency and a generator agree to study the production, export or combustion of hydrogen or ammonia. Many are signed during ministerial visits. Very few contain a price.

I do not regard hydrogen as a distraction. Some industries will need it, and some of the region's best solar and wind sites may one day make it cheaply. But I have reached a firm view about sequence. The first green hydrogen Southeast Asia can afford should replace grey hydrogen, the kind made from natural gas or coal that fertiliser plants and refineries already use. It should not be burnt in power stations until much later, if ever.

The arithmetic before the memorandum

Start with the cost of making it. An electrolyser needs roughly 50 to 55 kilowatt-hours of electricity for each kilogram of hydrogen. At a solar power price of US$45 a megawatt-hour, the electricity alone costs well over US$2 a kilogram. The electrolyser must then be paid for, and in our region it would work part-time: solar plants in Southeast Asia typically run at capacity factors in the mid to high teens, so an electrolyser fed only by solar sits idle for most of the day. Adding batteries or grid power to keep it busy raises either the cost or the carbon. Our own estimates for projects in the region put delivered green hydrogen at roughly US$5 to US$7 a kilogram before any subsidy.

Grey hydrogen made from gas costs roughly US$1.50 to US$2.50 a kilogram at the gas prices the region has seen in recent years, more when LNG is expensive. The gap is wide. Someone must pay it, and the candidates are a government, a customer or the producer's own shareholders. Most memoranda I have read are silent on which of the three it will be, which is usually a sign that each signatory assumes it will be one of the others.

Then consider what each kilogram achieves. A kilogram of hydrogen holds about 33 kilowatt-hours of energy. Burnt in an efficient combined-cycle turbine, it returns perhaps 18 to 20 kilowatt-hours of electricity. Made from electricity and turned back into electricity, well over half of the original energy is lost, and converting hydrogen into ammonia for shipping, then cracking or burning it, adds further losses. Used instead as a chemical feedstock in a fertiliser plant, the same kilogram displaces a kilogram of grey hydrogen directly, along with the 9 to 10 kilograms of carbon dioxide that making it from gas would have emitted.

Why co-firing is the most expensive first use

Ammonia co-firing at coal plants is the hydrogen proposal most often put to generators in this region. The idea is to replace part of the coal burnt in an existing boiler with ammonia and cut emissions in proportion. Trials elsewhere in Asia have shown that it can be done technically at a 20 per cent share of the fuel.

In 2023 we evaluated a US$95 million retrofit to co-fire ammonia at our 1,320-megawatt East Java plant. At a 20 per cent energy share, running as that plant does, it would have needed somewhere between 800,000 and 900,000 tonnes of ammonia a year. Green ammonia was not available at that scale at any price we could find. Ammonia made from gas without capturing its carbon would have cut emissions far less, or hardly at all once its production was counted. Even with our shadow carbon price applied, the cost of each tonne of carbon dioxide avoided was several times what the same money achieved by building solar and storage that displaced coal output outright.

There is a strategic hazard as well. Co-firing is often presented as a way to keep coal plants running into the 2040s and beyond. For an owner with a long contract that is attractive. For a power system trying to decarbonise, it can lock in an expensive fuel and a long-lived boiler just as cheaper alternatives arrive. I would rather negotiate an earlier closure, as we did in Johor, than spend capital on a retrofit whose main effect may be to delay one.

Where an electrolyser earns its place

If the first tonnes should go to existing users, the practical question is where those users are. Southeast Asia has fertiliser plants, refineries and petrochemical complexes that together consume large volumes of grey hydrogen, many of them on the coast and close to good solar or wind. A green hydrogen project supplying such a site replaces an existing fuel without new pipelines, new turbines or a new export buyer. It also gives the industry practical experience of electrolysers, water treatment, safety systems and intermittent supply, at a scale where mistakes are affordable and lessons travel.

That is the only form of hydrogen investment I now recommend to our board, and only as a pilot. We have agreed to study a small electrolyser at one of our Philippine wind farms, supplying an industrial gas buyer nearby, with a capped budget and an explicit decision point in 2028. We have declined to join two export memoranda that would have committed us to studies of large-scale ammonia production for North Asian buyers, because neither identified who would pay the cost gap.

None of this rules out a larger role later. Electrolyser costs may fall faster than I expect. Carbon prices in the region are rising, and a high enough price narrows the gap with grey hydrogen. Governments may decide to subsidise exports for industrial reasons of their own, and that would be a legitimate choice. If so, the economics will change and so will my advice.

Boards being asked to approve hydrogen strategies today should begin with two plain questions: what does each kilogram replace, and who pays the difference? A proposal that answers both deserves a hearing, even a small one. A proposal that answers neither should wait, however distinguished the signatories on its memorandum.