China
The world's largest power system, priced province by province: administered coal benchmarks and long-term contracts alongside real spot pilots, with a national unified market as the stated destination.
Overview
The largest power system on earth is also the hardest one to price. China generates more electricity than the United States, the European Union and India combined, and yet for most of that volume there is no single number a trader can point to and call the market.
What exists instead is a patchwork. Provinces run their own spot pilots — Guangdong, Shandong, Shanxi, Gansu and a growing list of others — while the bulk of energy still moves under annual and multi-year contracts negotiated at provincial level, anchored to an administered coal benchmark. Above that sits an inter-provincial layer, thin by comparison, and above that a stated destination: a national unified electricity market. Beijing has been saying so since 2015. It is still not built.
That is why China sits mid-spectrum. It is not an administered single-buyer system, and it is not a pool. It is a country where the price you get depends on which province you sit in, whether your plant is coal or wind, and what the local exchange decided this quarter.
Gas is a separate world with the same character. Three state producers — CNPC/PetroChina, Sinopec and CNOOC — dominate upstream and marketing, PipeChina was carved out in December 2019 to run the pipelines as a neutral operator, and city-gate prices for regulated users remain set by government formula. Around the edges of that, Chinese buyers do something with global consequences: they buy or refuse to buy LNG cargoes at the margin. China imported 67.36 million tonnes of LNG in 2025, 12% lower than 2024, and the shortfall was felt in every other Asian import market as JKM sagged.
China does not export power and barely exports gas. Its influence travels through the cargoes it does not take. A weak Chinese winter, a strong hydro year in Sichuan, another 300 GW of solar — each one loosens the global LNG balance without a single Chinese price ever printing on a screen you can see.
Market structure
Reform in China has run province by province rather than nationally, and the result is roughly thirty electricity markets with a common rulebook and very different clearing behaviour.
Who does what
| Function | Body | Role |
|---|---|---|
| Policy and pricing | NDRC | Sets benchmark tariffs, price bands and reform documents |
| Sector administration | NEA | Planning, licensing, dispatch rules, renewable targets |
| Transmission and dispatch | State Grid | Around 88% of the country by service territory |
| Transmission and dispatch | China Southern Power Grid | Guangdong, Guangxi, Yunnan, Guizhou, Hainan |
| Trading venues | Provincial exchanges | Plus Beijing and Guangzhou for inter-provincial trade |
The three layers of a Chinese power price
Most volume clears in medium- and long-term contracts, signed annually or monthly through the provincial exchange. These are physical, they carry delivery curves, and they are where generators and large industrial users actually settle. On top of that sits the spot pilot, which in the leading provinces now runs continuously with day-ahead and real-time clearing at nodal or zonal granularity. The spot is not a separate pot of energy — it is a deviation market that settles the difference between contracted position and actual delivery.
The third layer is inter-provincial. Power moving from Gansu to Zhejiang, or from Yunnan to Guangdong, trades through Beijing or Guangzhou under arrangements that owe more to planning quotas than to price signals. Provinces protect their own generators. An exporting province with cheap surplus wind and an importing province with expensive coal will not necessarily converge, because the transmission rights and the contract volumes were fixed administratively long before either price formed.
Retail competition exists, but not in the household segment. Industrial and commercial users have been pushed into the market wholesale — since 2021 essentially all of them buy at market-formed prices rather than the old catalogue tariff, either directly or through a retailer. Residential and agricultural users remain on regulated tariffs, cross-subsidised by everyone else.
Rules are national. Clearing is provincial. Full spot results are published unevenly, and for several pilot provinces the detailed clearing prices are not readily available outside China — which is a real constraint on anyone trying to build a comparable price history.
Infrastructure — power and gas
Two grid companies, a fleet of ultra-high-voltage lines built to move power a thousand miles east, and a gas network that was unbundled from its owners only in 2020.
Power
Two operators
State Grid covers most of the country; China Southern Power Grid covers the five southern provinces. Both are vertically integrated in everything except generation.
UHV backbone
Forty-five UHV projects are in operation, and west-to-east transfer capability was set to pass 340 GW by the end of 2025.
Renewable concentration
The wind and solar build is heaviest in the north and west — Inner Mongolia, Xinjiang, Gansu, Qinghai — a long way from the coastal load.
The UHV DC lines are the physical answer to a geographic problem: the resource is inland, the demand is on the coast. Each line is point-to-point, dedicated, and scheduled rather than economically dispatched. That matters commercially. A UHV link is not an interconnector in the European sense — it does not arbitrage a price difference, it delivers a contracted profile agreed between two provincial governments. Curtailment in the sending province and high prices in the receiving province can coexist quite happily.
Gas and LNG
Domestic production covers a large share of demand, supplemented by pipeline imports from Central Asia and Russia and by LNG into more than twenty coastal terminals. Power of Siberia 1 reached its full 38 bcm a year of design capacity in December 2024. Terminals are owned by the majors, by PipeChina and increasingly by provincial and private players, which has broadened the buyer base considerably.
PipeChina, established in December 2019 and operational from late 2020, took over roughly $56 billion of pipeline, storage and terminal assets from PetroChina, Sinopec and CNOOC. The point was third-party access — separate the pipe from the molecule, and a second-tier importer can reach an end user without asking a competitor for permission. In practice the majors remain the largest shareholders, and access terms are still where much of the commercial argument sits.
Schematic — system topology, not a geographic map. Resource sits inland, demand sits on the coast, and the link between them is contracted rather than priced.
Demand and supply
Demand keeps growing, coal keeps generating, and the renewable build is now large enough that in 2025 it stopped coal in its tracks for the first time in a decade.
Demand
Chinese electricity demand grows every year, driven by industry, air conditioning, electric vehicles and — the newest line item — data centres. There is no flat-demand story here of the kind Japan or Germany tell. The interesting question is what supplies the growth, and the answer changed in 2025: coal-fired generation fell by 71 TWh, the first decline since 2015, while wind and solar together reached 22% of output.
Supply
The build numbers are difficult to hold in your head. China added more than 430 GW of wind and solar capacity in 2025, taking the combined total to 1.84 billion kilowatts — 47.3% of installed capacity, overtaking thermal for the first time. Capacity is not energy, and coal still does the heavy lifting on a winter evening in Hebei. But the direction is no longer ambiguous.
| Indicator | Direction | Comment |
|---|---|---|
| Electricity demand | Rising | Industry, cooling, EVs and data centres |
| Coal generation | First fall since 2015 | Down 71 TWh in 2025 |
| Wind and solar | Rising fast | 22% of generation; curtailment risk rising with it |
| LNG imports | Falling | 67.36 Mt in 2025, down 12% year on year |
| Pipeline gas imports | Rising | Up 7.6% over January to November 2025 |
Rolling twelve months to March 2026. Source: Low Carbon Power, corroborated by Ember. Shares rounded; wind and solar together are reported at 22% of 2025 output by the State Council.
Sichuan and Yunnan hydro output swings by tens of terawatt-hours between a wet year and a dry one. A dry summer pulls coal burn up, pulls southern provinces onto imported power, and historically has been one of the better leading indicators for Chinese spot LNG buying.
Price setting mechanism
There is no single clearing price for Chinese electricity. There is a benchmark, a band around it, a contract stack that fills most of the volume, and — in the pilot provinces — a genuine marginal-cost auction sitting underneath.
The coal benchmark and its band
Coal-fired on-grid prices are built from a provincial benchmark tariff, and contracts may clear within a permitted range around it. That range used to be tight: 10% up, 15% down. Then came 2021. Coal prices spiralled, generators could not pass the cost through, plants stopped running and provinces started rationing industrial load. In October 2021 the NDRC widened the band to 20% in both directions and required all coal-fired power to enter market trading, with energy-intensive users explicitly denied the protection of the 20% cap.
That single document is the closest thing China has to a founding moment for market pricing. It did not create a spot market. It created a corridor wide enough for fuel costs to move through.
Spot pilots
In Guangdong, Shandong, Shanxi, Gansu and the other pilots, day-ahead and real-time markets clear on marginal cost with 15-minute settlement periods. Prices there behave the way a trader expects: negative or near-zero in the middle of a sunny Shandong day, spiking hard on a still winter evening. Provincial authorities set caps and floors, and they do intervene. Full clearing histories are not consistently published in English, which is the main practical obstacle to treating these as tradeable benchmarks.
Capacity and renewables
Coal plants have been paid a capacity payment since January 2024 — 30% or 50% of a benchmark plant's fixed costs, on an NDRC assessment of 330 yuan per kW — which added something like 5 to 8% to coal revenue in the first year. On the other side, Document 136 moved projects completed from 1 June 2025 onto market-based pricing with a CfD-style mechanism contract awarded by auction. Shandong's first auction cleared wind at 0.319 yuan/kWh and solar at 0.225 yuan/kWh.
It is a two-way difference contract against the market reference price for a fixed volume. Above the strike, the generator pays back. Below it, the generator is topped up. Familiar machinery — but the strike is set province by province, and by October 2025 only eighteen provinces had finalised their rules.
Gas
City-gate prices for regulated demand remain administered, with residential supply cross-subsidised and industrial contracts increasingly linked to import cost. Imported LNG is bought against JKM, against Brent slopes on term contracts, and against a domestic price that does not always clear the arbitrage — which is precisely why Chinese buyers resell cargoes rather than take them.
Regulatory regime
China has no independent energy regulator in the sense a British or American trader would recognise. It has ministries, and it has grid companies, and the line between policy and pricing runs straight through the same institution.
| Body | Remit |
|---|---|
| NDRC | Macroeconomic planning, benchmark tariffs, price bands, reform documents |
| NEA | Sector administration, planning, dispatch and renewable policy; sits under NDRC |
| Provincial DRCs and energy bureaus | Local market rules, spot pilot design, caps and floors |
| State Grid / China Southern Power Grid | Transmission, distribution and dispatch; also run the trading platforms |
| SASAC | State ownership of the grid companies, the generation groups and the oil majors |
Why the difference matters
An independent regulator can be lobbied, litigated against and appealed. The NDRC cannot, in any way that a foreign counterparty can use. Price decisions arrive as documents — numbered, published, effective immediately — and the market adjusts. Document 136 is the recent example: a policy note that rewrote the revenue model for every renewable project in the country, issued in February 2025 and binding from June.
The reform arc
Document 9 in 2015 opened the sector to trading and set up provincial exchanges. Spot pilots followed from 2017, eight of them initially, expanding since. The 2021 coal crisis forced the pricing band open. Capacity payments arrived in 2024, renewable market pricing in 2025. Each step has been incremental and each has been reversible in principle, because the same body that granted the freedom retains the power to withdraw it.
The national unified market
Beijing's stated destination is a single national market with inter-provincial trading on the same footing as intra-provincial. Rules for that framework have been issued. The obstacle is not technical — it is that provincial governments own the fiscal consequences of their local generators, and a genuinely national merit order would strand some of them. Watch for the moment a province accepts imported power displacing its own coal fleet without a compensating quota. That is when the reform becomes real.
For anyone holding Chinese exposure, the practical rule is that NDRC publication schedules matter more than fundamentals over any horizon shorter than a quarter.
Key links
Primary sources for this market. Figures on this page are drawn from these and from published market data.