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China national: 5 energy policy briefs

The energy policies moving China national’s power markets, one brief each: the problem, the mechanism, the market effect, who gains and who pays, where it stands on the path to binding law, and the official text.

Document 136 · market-based pricing for wind and solar with a sustainable-development settlement mechanism

China national · National Development and Reform Commission and National Energy Administration · notice · 2025

Where it stands: Notice in force; provincial rules issued; annual mechanism-price auctions running

From 1 June 2025 all new wind and solar output in China is sold at market prices instead of the coal benchmark tariff, with a CfD-like mechanism price set by provincial competitive bidding for a share of output; projects commissioned before June 2025 keep a price no higher than the coal benchmark, which is why the first half of 2025 saw a record installation rush and the second half a collapse.

The problem

China's wind and solar were paid the provincial coal benchmark tariff outside the market even as spot markets spread, which shielded them from midday negative prices, distorted the value of storage and flexibility, and put the cost of integrating hundreds of gigawatts of new capacity on grid companies and coal plants. With more than 1,400 GW of wind and solar installed by 2024, the NDRC judged that the fleet must take market risk.

What it does

NDRC and NEA Notice No. 136 of 2025, issued 9 February 2025, requires that all on-grid electricity from wind and solar enter the market (medium- and long-term contracts and spot) with prices formed by the market, ending the guaranteed benchmark tariff. To keep investment flowing it creates a sustainable-development price settlement mechanism operated outside the market: for a project's mechanism-covered volume (a share of output set by the province), the difference between the market price and a mechanism price is settled by the grid company and recovered from users through system charges. For existing projects (grid-connected before 1 June 2025) the mechanism price is no higher than the coal benchmark and the covered volume and term follow existing rules. For new projects (from 1 June 2025) the mechanism price and volumes are determined by annual provincial competitive bidding, with a price cap and floor, the covered share set by each province, and a term tied to the technology's typical cost-recovery period. Provinces must publish implementation rules, and the document requires that market rules be adapted so renewables can participate in spot markets and that the green-certificate value be counted separately.

Market effect

The notice moved Chinese renewables from feed-in to merchant-plus-CfD in one step. New projects now face the provincial spot price, which in solar-rich provinces (Shandong, Gansu, Qinghai, Ningxia) has frequent midday prices near zero or negative, so project economics depend on winning a mechanism price in the bidding and on the covered share; the first provincial auctions in the second half of 2025 cleared at prices well below the coal benchmark (in Shandong and Guangdong by margins of 20 to 40 percent), which cut developer returns and prompted a sharp fall in new installations after the June cut-off, following a record 200 GW-plus of solar added in the first five months of 2025. Storage co-location and curtailment management became central to project value, and green certificates became a separate revenue line. Coal plants benefit from renewables taking price risk, and the provincial bidding creates a public, comparable series of strike prices, the closest China has to a renewable auction market. Cost pass-through to users appears in the system operation charges. The notice is binding but its economics are set province by province.

Key numbers

Issued
9 February 2025 (NDRC/NEA No. 136)
Cut-off for grandfathering
Grid connection before 1 June 2025
Installation rush
More than 200 GW of solar added January to May 2025
First provincial auction outcomes
Mechanism prices 20 to 40 percent below coal benchmarks in leading provinces

Who gains and who pays

  • Wind and solar developers (state-owned power groups, private IPPs) (costs): Market price exposure; returns depend on provincial mechanism-price auctions.
  • Existing projects connected before 1 June 2025 (gains): Grandfathered mechanism price up to the coal benchmark.
  • Grid companies (obligation): Operate settlement and collect system charges.
  • Storage and flexibility providers (gains): Higher value of shifting renewable output away from low-price hours.
  • Coal generators (gains): Renewables bear price risk; coal keeps capacity payments.
  • Electricity users (mixed): Pay mechanism settlements via system charges; benefit from lower market prices.

Implementation

All provinces issued implementation rules during 2025 and ran their first mechanism-price auctions for new projects in the second half of 2025, with annual rounds thereafter. NDRC has issued follow-up guidance on how mechanism volumes interact with renewable consumption weights and green certificates. Watch provincial auction results (price, covered share, term) as the leading indicator of Chinese renewable build rates and module demand.

Concerns

  • Collapse in new renewable investment if mechanism prices fall too far
  • Provincial variation creating an uneven playing field
  • Curtailment and negative prices in renewable-rich provinces
  • Cost recovery from users through system charges
  • Coordination with the green-certificate and renewable-consumption systems

Dates to watch

  • 2026: Second-round provincial mechanism-price auctions and installation data

Sources

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National emissions trading system expansion to steel, cement and aluminium

China national · Ministry of Ecology and Environment · notice · 2025

Where it stands: Expansion in force; first compliance (2024 year) completed December 2025; fully free allocation through 2026; tightening from 2027, cap-based and part-paid market targeted by 2030

In March 2025 the Ministry of Ecology and Environment extended China's national ETS, which had covered only power since 2021, to steel, cement and aluminium smelting, adding about 1,500 enterprises and 3 billion tonnes of CO2, with free allocation and intensity-based benchmarks at first and a transition toward absolute caps and tighter benchmarks; for the power sector the 2024 to 2026 allocation plans tighten benchmarks while allocation remains fully free, with a cap-based, part-paid market targeted by 2030.

The problem

China's ETS covered about 2,200 power companies and 5 billion tonnes of CO2 but with free, intensity-based allocation and a low price (roughly 50 to 106 yuan per tonne across 2024 and 2025), it did little to change dispatch. To meet the 2030 peaking goal, respond to the EU CBAM and move toward absolute caps, the ETS needed to cover heavy industry and to start charging for allowances.

What it does

The Ministry of Ecology and Environment's work plan of March 2025 brings steel, cement and aluminium smelting into the national ETS starting with the 2024 compliance year, with allowances allocated free at intensity benchmarks during a 2024 to 2026 introductory period and total allocation matched to actual emissions; from 2027 the sectors move to a tightened allocation with the possibility of a declining absolute cap. For the power sector, the 2024 to 2026 allocation plans tightened benchmarks by unit type and retained a cap on shortfalls; allocation remains fully free, and the plan for 2025 and 2026 issued on 1 September 2026 (Guohuanguiqihou [2026] No. 1) says only that it lays the groundwork for combining free and paid allocation in later years. The Interim Regulations on Carbon Emissions Trading Management, a State Council regulation in force since May 2024, give the scheme legal standing and penalties. The China Certified Emission Reduction offset market reopened in 2024 with methodologies for forestry, solar thermal, offshore wind and mangroves, allowing up to 5 percent offset use. The August 2025 Party and State Council opinions on strengthening the national carbon market set allowance caps for sectors with stable emissions by 2027 and a cap-based market combining free and paid allocation by 2030, and the ETS is expected to add further sectors (chemicals, petrochemicals, paper, aviation).

Market effect

For power, the tighter benchmarks and beginning of paid allocation raise the marginal cost of the least efficient coal units and, as spot markets spread, begin to appear in energy bids, which slightly favours efficient supercritical units and gas in the merit order; at current allowance prices the effect on dispatch is small (about 0.01 to 0.05 yuan per kWh between best and worst units). The industrial expansion matters more for electricity demand: steel, cement and aluminium are the largest industrial power users and now carry a carbon cost on both direct and, for aluminium, indirect emissions from purchased electricity, which increases demand for green power and green certificates and rewards relocation to renewable-rich provinces (Yunnan, Inner Mongolia). The offset market gives renewable and forestry projects a modest additional revenue stream. An eventual absolute cap and higher prices would strengthen these effects and align China's carbon price closer to levels creditable under the EU CBAM.

Key numbers

Expansion announced
Work plan signed 20 March 2025, published 26 March 2025; applies from the 2024 compliance year
Sectors added
Steel, cement, aluminium smelting: about 1,500 entities and 3 billion tonnes estimated; 1,291 entities listed for 2025 (232 steel, 962 cement, 97 aluminium)
Allowance price range
Roughly 50 to 106 yuan per tonne across 2024 and 2025: 2024 traded 69.67 to 106.02 (year-end 97.49); 2025 closed at 74.63, average 62.36
Offset use limit
Up to 5 percent of the surrender obligation with CCERs (2021 Measures, Article 29)

Who gains and who pays

  • Steel, cement and aluminium producers (obligation): ETS compliance from the 2024 year; free allocation initially.
  • Coal power generators (costs): Tighter benchmarks; paid allocation not yet started.
  • Renewable generators and green-certificate sellers (gains): Higher industrial demand for green power and offsets.
  • Aluminium smelters in coal-heavy provinces (costs): Indirect emissions from purchased power counted.
  • Offset project developers (gains): CCER market reopened with approved methodologies.

Implementation

Newly covered enterprises reported and verified 2024 emissions during 2025 and completed their first compliance by 31 December 2025 (MEE reported 99.99 percent completion across 3,378 entities: 2,087 power, 232 steel, 962 cement and 97 aluminium). 2025-year compliance for all four sectors is due by 31 December 2026 under the allocation plan issued on 1 September 2026. Watch the 2027 allocation plan for the first absolute caps and any start of paid allocation, and the allowance price on the Shanghai Environment and Energy Exchange.

Concerns

  • Low allowance prices limiting abatement
  • Free allocation delaying real cost pressure
  • Data quality and verification in newly covered sectors
  • Interaction with provincial pilot ETSs
  • Trade exposure and CBAM recognition of the Chinese carbon price

Dates to watch

  • 31 December 2026: 2025-year compliance deadline for power, steel, cement and aluminium
  • 2027: First deepening-phase allocation plan: caps for stable-emission sectors and possible start of paid allocation
  • 2030: Target for a cap-based market combining free and paid allocation

Sources

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Energy Law of the People's Republic of China (adopted November 2024, effective 1 January 2025)

China national · National People's Congress Standing Committee · statute · 2024

Where it stands: In force; implementing regulations and sector-law revisions being drafted

China's first comprehensive energy statute, in force from 2025, gives legal priority to renewable development, a statutory basis for green certificates and energy markets, recognises hydrogen as an energy source, and codifies planning, reserves and emergency powers; it is a framework law whose bite comes through State Council regulations and NDRC/NEA measures.

The problem

China regulated energy through sector laws (Electricity Law 1995, Coal Law, Renewable Energy Law 2005, Energy Conservation Law) and administrative notices, with no overarching statute after two decades of drafting. The dual-carbon goals (peak before 2030, neutrality before 2060) and the push for a unified national electricity market needed a legal basis for market-based pricing, renewable priority and cross-provincial coordination.

What it does

The NPC Standing Committee adopted the Energy Law on 8 November 2024 after three readings and public comment on the April 2024 draft; it took effect on 1 January 2025 with nine chapters and 80 articles. It establishes energy planning as a statutory function, provides that the state prioritises the development of renewable energy and sets a renewable consumption minimum ratio mechanism, gives green electricity certificates legal status as the certification of renewable environmental attributes, and requires a unified national energy market with market-determined prices where competition is possible and government-set prices for natural monopoly links (transmission and distribution). It includes hydrogen in the definition of energy, codifies strategic reserves and emergency response, calls for the orderly development of nuclear and the clean and efficient use of coal, and provides for rural energy, science and technology support and international cooperation. Detailed obligations are delegated to State Council regulations and sector measures.

Market effect

The law's direct market effect is limited because it is a framework, but three provisions matter. The statutory renewable consumption ratio underpins the provincial renewable consumption responsibility weights and the green-certificate market, converting policy targets into legal obligations on grid companies and large users; the recognition of green certificates supports their use for export-facing companies and for the mandatory green-power consumption ratios applied to data centres and heavy industry from 2025. The market-pricing principle gives legal cover to the spot-market roll-out and to Document 136's market-based pricing of new renewables. The coal and nuclear provisions signal continued approval of coal capacity for security while shifting its role toward capacity provision under the capacity-payment mechanism. For foreign traders the law is mostly a signal of direction; the operative rules remain NDRC and NEA notices.

Key numbers

Adopted
8 November 2024
Effective
1 January 2025
Structure
9 chapters, 80 articles
Drafting history
Roughly two decades; draft published April 2024

Who gains and who pays

  • Grid companies (State Grid, China Southern Grid) (obligation): Renewable consumption obligations and market operation duties.
  • Renewable generators (gains): Statutory priority and green certificate recognition.
  • Large electricity users and data centres (obligation): Renewable consumption ratios with green-certificate compliance.
  • Coal generators (mixed): Continued role for security; shift to capacity provision.
  • Hydrogen developers (gains): Hydrogen recognised as an energy source, enabling sector regulation.

Implementation

Implementing regulations and revisions to the Electricity Law and Renewable Energy Law are on the State Council and NPC legislative plans; NDRC and NEA have issued measures on green certificates, renewable consumption weights and market rules that reference the law. Provincial energy laws are being aligned. Watch the NPC legislative plan for the Electricity Law revision, which will carry the market-specific rules.

Concerns

  • Framework provisions with little direct enforceability
  • Tension between market pricing and continued administrative price setting
  • Coal security provisions slowing decarbonisation
  • Provincial protectionism against cross-provincial market integration
  • Data and transparency for foreign participants

Dates to watch

  • 2026: Electricity Law revision draft and green-certificate implementing measures

Sources

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Coal power capacity pricing mechanism (from 1 January 2024)

China national · National Development and Reform Commission and National Energy Administration · notice · 2023

Where it stands: Mechanism in force since 2024; step-up to at least 50 percent of fixed cost from 2026

Since 2024 China pays coal plants a fixed capacity charge, 100 yuan per kW-year in most provinces (about 30 percent of a plant's fixed cost) and 165 yuan in provinces with heavy renewables, rising toward 50 percent of fixed cost from 2026, recovered from users; it turns coal into the paid backbone of a renewables-led system and is the first two-part tariff in China's power market.

The problem

As wind and solar grew, coal plants ran fewer hours (below 4,500 a year on average) and lost money, yet the system needed them for peak and ramping; energy-only market prices with caps could not fund their fixed costs, and provinces feared shortages like those of 2021 and 2022. The NDRC chose an administered capacity payment rather than a competitive capacity market.

What it does

NDRC and NEA Notice No. 1501 of 2023, issued in November 2023 and effective 1 January 2024, sets a two-part tariff for coal-fired units that meet dispatch and performance requirements: an energy price formed in the market and a capacity price set by the state. The capacity price is calculated from a benchmark fixed cost of 330 yuan per kW-year, with the 2024 to 2025 capacity price recovering about 30 percent of that (100 yuan per kW-year) in most provinces and about 50 percent (165 yuan per kW-year) in provinces with tighter supply or higher renewable shares (including Yunnan, Sichuan, Qinghai, Chongqing, Henan, Hunan and Guangxi). From 2026 the recovery share is to rise to at least 50 percent nationwide, and provinces may go higher. Plants that fail to deliver when called face deductions and, on repeated failure, loss of the payment. The charge is recovered from industrial and commercial users through the system operation cost component of retail prices and is not paid by residential and agricultural users.

Market effect

The capacity payment removed the bankruptcy pressure on coal generators (the big five state groups returned to profit in 2023 and 2024) and let coal plants bid lower energy prices, which pushes spot prices down in provinces with spot markets and compresses the margin for gas plants and storage that rely on energy-price spreads. It also finances the retrofits for flexibility (deep peaking, faster ramping) that renewables integration requires, effectively making coal the firming resource paid by users. Because the payment is administered, it does not signal where new capacity is needed, and new coal approvals continued at tens of gigawatts a year in 2024 and 2025, raising the risk of stranded capacity later. For industrial users the charge adds roughly 0.01 to 0.02 yuan per kWh. The 2026 step-up increases both the security of coal cash flows and the cost borne by users, while the same logic is being extended to gas and pumped-storage capacity tariffs and to storage in some provinces.

Key numbers

Effective
1 January 2024
Benchmark fixed cost
330 yuan per kW-year
2024 to 2025 capacity price
100 yuan per kW-year (30 percent); 165 yuan (50 percent) in designated provinces
From 2026
At least 50 percent of fixed cost nationwide

Who gains and who pays

  • Coal generators (Huaneng, Datang, Huadian, State Power Investment, Guodian) (gains): Fixed capacity revenue; lower energy-price bids.
  • Industrial and commercial users (costs): Pay the capacity charge through system operation costs.
  • Storage and gas peakers (costs): Compressed energy spreads; partial parallel capacity tariffs in some provinces.
  • Renewable generators (mixed): Firming provided; lower spot prices under Document 136 exposure.
  • Provincial governments (obligation): Set within-band prices and enforce performance.

Implementation

Provinces implemented the mechanism in 2024 with performance assessment rules; the 2026 step-up requires provincial price notices. Parallel notices have introduced capacity or two-part tariffs for pumped storage (2023) and gas peaking (in several provinces) and pilots for new-type storage. Watch NDRC's 2026 price notice and any move toward a competitive capacity mechanism as the unified national market develops.

Concerns

  • Locking in coal capacity and new coal approvals
  • Cost to industrial users as the share rises
  • Lack of a locational or competitive signal
  • Fairness relative to storage and gas capacity
  • Performance enforcement across provinces

Dates to watch

  • 1 January 2026: Capacity price rises to at least 50 percent of benchmark fixed cost

Sources

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Electricity spot market basic rules and the unified national electricity market roadmap

China national · National Development and Reform Commission and National Energy Administration · notice · 2023

Where it stands: Basic rules in force; provincial spot markets at basic full coverage; formal operation nationwide targeted before 2027, unified national market basically built by 2030 and fully by 2035

The 2023 basic rules standardised provincial spot markets (day-ahead and real-time, nodal or zonal pricing, contracts settled as financial hedges), and the 2022 guiding opinions, the April 2025 spot-acceleration notice and the February 2026 State Council Office opinions set the timetable: full provincial spot coverage by end-2025, formal operation nationwide before 2027, and a unified national market basically built by 2030 and fully by 2035, plus inter-provincial spot trading through the two national exchanges.

The problem

China's power was traded mostly through annual medium- and long-term contracts at administered or lightly negotiated prices, with dispatch by plan and inter-provincial trade managed bilaterally; that could not integrate variable renewables, price flexibility or move power efficiently from the west to coastal load centres. Spot pilots in Guangdong, Shanxi, Shandong and other provinces since 2018 needed a common rulebook and a path to national integration.

What it does

The Basic Rules for the Electricity Spot Market (Trial), issued by NDRC and NEA in September 2023, define the structure of provincial spot markets: day-ahead and real-time markets with locational marginal pricing or zonal pricing, participation by generators, retailers, large users and storage, price caps and floors, settlement of medium- and long-term contracts as financial differences against spot, and the phased inclusion of renewables and demand response. Companion rules cover inter-provincial spot trading through the Beijing Power Exchange and Guangzhou Power Exchange, ancillary services and market surveillance. The January 2022 guiding opinions on accelerating a unified national electricity market (NDRC/NEA Document 118) set 2025 for initial and 2030 for basic completion; the April 2025 notice on comprehensively accelerating spot market construction (Document 394) required basic full coverage of spot markets with continuous settlement by the end of 2025; and the State Council Office's February 2026 implementation opinions on perfecting the unified national market (Guobanfa [2026] No. 4) set the operative gates: spot markets basically all in formal operation before 2027, the unified national market basically built by 2030 and fully built by 2035 (the 2029 date in the November 2024 Blue Book was a planning target, not a binding one). By September 2025 seven provinces (Shanxi, Guangdong, Shandong, Gansu, Western Inner Mongolia, Hubei and Zhejiang) were in formal operation; NEA reported basic full coverage of provincial spot markets in June 2026 and expects more than half of provinces to be in formal operation during 2026, with the rest in continuous-settlement trials.

Market effect

Spot markets are where Document 136's renewable pricing, the coal capacity payment and storage economics are settled, so their roll-out determines how those policies bite. Provinces in formal operation show high midday price collapse in solar-heavy regions, evening peaks and growing storage arbitrage; Shandong has recorded extended negative-price periods. Medium- and long-term contracts settling against spot have turned China's annual contract market into a hedging market with basis risk, creating demand for risk management among retailers and large users. Inter-provincial spot trading (west-to-east) begins to arbitrage provincial price differences and supports the ultra-high-voltage line economics. A unified national market, basically built by 2030 under the 2026 opinions, would gradually erode provincial protectionism that keeps prices administered in importing provinces. For foreign observers, provincial spot prices are now the most informative signal of Chinese power fundamentals, and the exchanges publish them.

Key numbers

Basic spot rules issued
Signed 7 September 2023, published 15 September 2023 (NDRC/NEA Document 1217)
Provincial spot coverage target
Basic full coverage by end-2025 (Document 394); NEA reported it achieved in June 2026
National market target
Basically built by 2030, fully built by 2035 (Guobanfa [2026] No. 4); 2029 was the 2024 Blue Book target
Provinces in formal spot operation
Seven by September 2025: Shanxi, Guangdong, Shandong, Gansu, Western Inner Mongolia, Hubei, Zhejiang; NEA expects more than half of provinces during 2026

Who gains and who pays

  • Generators (coal, gas, renewables, storage) (mixed): Market price exposure; new revenue from ancillary services and arbitrage.
  • Retail companies and large users (obligation): Must manage spot and contract basis risk.
  • Grid companies and power exchanges (obligation): Operate markets, settlement and inter-provincial trading platforms.
  • Provincial governments (mixed): Lose some pricing control; gain integration benefits.
  • Storage developers (gains): Spot spreads and ancillary-service markets provide revenue.

Implementation

NEA tracks each province's transition from trial to formal operation and NDRC issues annual work plans for market construction; revised inter-provincial spot trading rules were approved in April 2026 (NDRC Document 275) to increase traded volumes, and NDRC/NEA issued basic rules for the medium- and long-term market in December 2025. Regional markets (Southern China) are being formed as building blocks. Watch NEA's reports on provinces entering formal operation and the 2027 gate for spot markets in formal operation nationwide.

Concerns

  • Provincial protectionism limiting cross-border trade
  • Price caps and administrative intervention during tight periods
  • Market power of large state generators in provincial markets
  • Financial risk for retailers without hedging tools
  • Uneven pace across provinces

Dates to watch

  • 2026: NEA confirmation of provinces entering formal spot operation (more than half expected in 2026); revised inter-provincial spot rules in force since April 2026
  • 2027: Gate for spot markets basically all in formal operation
  • 2030: Unified national electricity market basically built (fully built by 2035)

Sources

Checked against sources on .