A major overhaul of Guangdong's gas power dispatch policy is pushing gas-fired generation from baseload operations into mostly peak-only roles, which could dampen long-term gas demand expansion in China's power sector, according to new analysis by Wood Mackenzie presented at Gastech 2026. Kai Dong, Principal Analyst for Asia Pacific Gas and LNG, called the "Guangdong Model" a blueprint for how the country's biggest gas power market is responding to a grid increasingly dominated by renewables. The shift holds major implications for global LNG markets, as other Chinese provinces adopt similar frameworks.
Guangdong represents 10% of China's GDP and roughly one-third of the nation's total gas power capacity. In 2025, the province consumed 41 billion cubic meters of gas and had LNG demand of 18 million tonnes, accounting for 10% and 28% of national totals, respectively. Between 2020 and 2026, gas-fired capacity in Guangdong more than doubled, jumping from 27 GW to 61 GW, while renewable capacity surged nearly eightfold, climbing from 14 GW to 105 GW. Coal and nuclear generation expanded more slowly, continuing to support baseload demand. The rapid buildout of solar and wind drove demand for flexible, dispatchable generation to balance intermittent output, strengthening gas power's role as a system regulator.
Guangdong's July 2025 gas power policy reform marks a significant departure from the previous model, according to the report. Gas plants previously operated with guaranteed dispatch hours, an approved on-grid tariff, and additional subsidies when the system-wide weighted average cost of gas exceeded certain levels. The new policy introduces pure economic dispatch, requiring plants to bid to recover fuel costs. In exchange, capacity payments have increased significantly, now covering full capital expenditure instead of only partial recovery. "Between 2020 and 2026, gas-fired capacity more than doubled in the province while renewable capacity grew almost eightfold," said Kai Dong. "Guangdong's experience tells us that gas power fleets can successfully reposition themselves in the grid of increasing renewables."
The report's analysis indicates that spot LNG prices must fall to approximately $6 per million British thermal units—after accounting for taxes, regasification, and pipeline tariffs—before efficient gas power fleets can economically displace subcritical coal plants, assuming a $95-per-ton coal price. Until prices drop that low, most fleets are expected to remain primarily in peaking roles, limiting their contribution to total power gas demand. The policy compensates plants for availability rather than generation, formalizing the transition to peaking operations. Wood Mackenzie forecasts that shifting to peak-only dispatch will slow the growth of China's power gas demand compared to maintaining baseload operations, a structural change with reach far beyond Guangdong.
The implications for global LNG markets hinge on national replication. "Gas-fired power capacity in China will continue to grow to support grid stability in a high-renewable system," Dong said. "The policy shift means plants will run fewer hours, and that distinction matters enormously for China's gas market." With other Chinese provinces following a similar framework, the key question for the global LNG market is how much less demand growth this could mean than previously anticipated. While gas capacity will keep expanding to ensure grid stability in a renewables-heavy system, the reduced operating hours represent a structural downside for gas demand growth, reshaping expectations for one of the world's largest LNG importers.