China's national carbon market briefly touched 100 yuan/t for the first time on August 3, before closing below 99 yuan/t and easing further to 98.56 yuan/t the next day. The repeated failure to break the 100-yuan threshold, however, has sent a clear price signal.

The market, launched in July 2021 with an opening trade at 52.78 yuan/t, traded in a narrow 55-60 yuan/t range for two years before the real rally began in early 2024. Prices first broke above 100 yuan/t in April 2024, hit an intraday high of 104 yuan/t, and reached a then-record 106 yuan/t in November.

Prices then entered a downtrend, falling from 97 yuan/t to below 68 yuan/t in the first half of 2025, a decline of nearly 30%. The 2025 decline was driven by looser policy and market expansion, but prices have now surged back toward the 100-yuan mark with greater momentum, rising over 18% in July alone.

The current rally is underpinned by two converging factors. Total trading volume of carbon emission allowances (CEA) in the national market reached 17.26 million tonnes in July, with the highest price touching 99.50 yuan/t. The closing price on the last trading day of July rose 18.30% from the end of June.

In late July, the Ministry of Ecology and Environment released a draft plan for allowance allocation for the power sector in 2025-2026 and for steel, cement and aluminium smelting in 2026, signalling two tightening measures: the pre-allocation ratio was cut from 70% to 50%, reducing free allowances, while cross-year banking of unused allowances was eliminated. With the carry-over policy discontinued, the carbon market is shifting from a buyer's to a seller's market, putting upward pressure on prices.

Meanwhile, steel, cement and aluminium smelting have been formally incorporated into the national carbon market, expanding coverage from about 4.5 billion tonnes of emissions to about 7.5 billion tonnes. The number of regulated companies has grown from around 2,200 to roughly 4,000, raising the market's share of national carbon emissions from 38% to about 55%. Cumulative trading volume in the national carbon market surpassed 930 million tonnes by the end of July.

The 100-yuan carbon price has its most direct cost impact on coal-fired power. With the world's largest installed coal power capacity and emissions accounting for about 40% of the national total, the sector is the carbon market's biggest buyer.

Calculations show that if the carbon price rises from 100 yuan/t to 200 yuan/t, the cost per kWh of coal power increases by 0.094 yuan, while gas power costs rise by 0.048 yuan per kWh. Should carbon prices climb to 150-200 yuan/t, thermal power carbon costs would increase by 139-185 yuan per MWh .

Carbon costs are being steadily internalised into generation costs, further eroding coal power's price competitiveness in the electricity market. Rigid compliance obligations are intensifying panic among companies with allowance shortfalls, driving strong purchasing demand.

Policy positioning for coal power is also shifting as carbon prices rise. The 15th "Five-Year Plan" for new power system construction, issued in early August, reclassifies coal power from a "baseload security power source" to a "supporting and regulating power source". The 15th "Five-Year Plan" for new energy system development sets targets for coal consumption to peak by 2030, with non-fossil energy accounting for 25% of consumption and 50% of power generation.

The adjustment does not negate coal power's backstop role but defines a boundary: coal power yields to renewables under normal conditions while remaining available for extreme conditions. Coal power's share of national generation fell below 50% for the first time in the first half of 2026, and its growth space is narrowing.

Under mounting pressure, coal power revenue structures are also changing. A notice on improving capacity pricing mechanisms for the generation side, issued in January, requires that capacity prices recover at least 50% of fixed costs for coal power units. This means even if generation declines, units can recover more than half of fixed costs through capacity payments.

Calculations show that under current coal prices, more than 20 provinces face losses on 2026 long-term contracts versus local coal power cash costs. With carbon prices rising and coal price pressure persisting, the operational difficulties of coal power companies are spreading from individual provinces to a broader scale.