A new national framework links revenues to performance, reshaping investment incentives, technology choices, and market discipline across China’s rapidly growing storage sector
China has taken a critical step toward establishing energy storage as a core pillar of its power system. On January 30, the National Development and Reform Commission (NDRC) and the National Energy Administration (NEA) jointly issued the Notice on Improving the Generation-Side Capacity Pricing Mechanism (Policy No. 114).
For the first time at the national level, new-type energy storage (NTES) is explicitly entitled to capacity payments under a clearly defined calculation framework. Within the industry, the move has been widely described as “the final missing piece” in the energy storage revenue model.
The policy arrives at a pivotal juncture. China’s power system is grappling with rapid renewable penetration, widening peak–valley load gaps, and rising demands for system flexibility and reliability. By anchoring a portion of storage revenues to capacity payments, rather than relying almost exclusively on energy arbitrage and ancillary services, China is signaling a shift from localized experimentation toward a unified, bankable market design.
The policy and its market significance
Policy No. 114 introduces a phased, three-step approach to capacity remuneration for new energy storage.
In the first stage, capacity payments are benchmarked to local coal-fired power capacity tariffs and adjusted by a conversion factor reflecting peak-shaving capability.
In the second stage, once power spot markets are operating on a continuous basis, capacity compensation will be based on covering the unrecovered fixed costs of marginal generators. Compensation levels will be determined by balancing power supply–demand conditions, consumer affordability, and the maturity of electricity market reforms.
In the final stage, when conditions are deemed sufficient, a fully market-based capacity market will be introduced, with prices formed through competitive bidding mechanisms.
These stages are designed to be sequential, with increasing marketization gradually replacing administrative pricing. Unlike the patchwork of provincial pilots seen in recent years, Policy No. 114 establishes a unified national framework. For investors, this significantly improves policy predictability, an essential consideration for long-lived, capital-intensive infrastructure assets.
Capacity pricing calculation
At the core of the policy is a transparent pricing formula. Storage capacity tariffs are based on local coal power capacity prices and multiplied by a “peak contribution” coefficient, calculated as the ratio of a storage system’s continuous full-power discharge duration to the longest annual net load peak, capped at 1.0.
In practice, this structure strongly favors longer-duration systems. Provinces that have already disclosed indicative parameters illustrate the effect. Hebei, Gansu, and Hubei have published peak duration caps of 4 hours, 6 hours, and 10 hours, respectively. Under these assumptions, a 2-hour storage system would receive only 50%, 33%, or 20% of the full capacity tariff in those provinces.
As of early February, sixteen provincial grids had announced 2026 coal power capacity prices. Gansu and Yunnan have raised tariffs to the upper limit of CNY 330 per kW·year; Sichuan and Tianjin have set prices at CNY 231 per kW·year; while most other provinces have adopted CNY 165 per kW·year. Because storage capacity prices are explicitly capped at coal benchmarks, these figures effectively define the ceiling for storage capacity revenues nationwide.
Commercial impact: improving returns, expanding the market
According to estimates by China Securities (CSC), a capacity tariff range of CNY 165–330 per kW·year translates into incremental revenue of roughly CNY 0.08–0.16 per kWh. For storage projects, this can raise internal rates of return (IRR) by 3–4 percentage points, materially improving the economics of marginal projects and providing a meaningful hedge against cost volatility.
Capacity payments are expected to account for around 30% of total storage revenues. While energy arbitrage and ancillary services remain important, the introduction of a stable, fixed-income component lowers overall risk profiles and broadens the pool of investable projects, particularly in provinces where storage economics were previously marginal.
China’s storage market is already sizable. By the end of 2025, the cumulative installed capacity of new-type energy storage reached 144.7 GW/373.7 GWh, representing year-on-year increases of 85% and 103%, respectively. Newly commissioned projects averaged 2.85 hours in duration, with 2–4 hour systems accounting for roughly 80% of new additions.
Policy No. 114 is likely to reshape the storage market in China. Under the new framework, cumulative storage capacity could reach 370–450 GW by 2030, implying a five-year compound annual growth rate of 20.7–25.5%.
Duration, efficiency, and dispatchability
Beyond improving headline economics, the new policy fundamentally changes how storage assets are valued. Revenues are increasingly tied not only to installed capacity, but also to duration, efficiency, and operational performance, placing greater emphasis on engineering quality and execution discipline.
For manufacturers and developers, three technical trends stand out.
First, long-duration storage is poised to gain ground. Because capacity payments scale with discharge duration, systems exceeding four hours—such as vanadium redox flow batteries (VRFBs), long-duration lithium iron phosphate (LFP) batteries, sodium-ion batteries, and compressed air energy storage—stand to benefit. Although longer durations come with higher capital costs, the fixed-income nature of capacity payments may shift investment decisions for certain projects.
Second, round-trip efficiency has become economically critical. Policy No. 114 clarifies that independent storage facilities are treated as electricity consumers when charging and must pay transmission and distribution fees, system operation charges, and line-loss costs. When discharging, only transmission and distribution fees are refunded; line-loss and system operation fees are not.
From February 2026, system operation fees are expected to rise in some provinces, exceeding CNY 0.1 per kWh in eleven provincial grids. Inefficient systems, or poorly optimized dispatch strategies, will therefore face significantly higher net costs. High-efficiency hardware, advanced energy management systems, and data-driven operational optimization are no longer optional; they are central to sustained profitability.
Third, performance compliance is tightening. The policy emphasizes stricter assessments of capacity payments to incentivize reliable operation. Hubei’s January 2026 rules provide a clear signal: if a storage system’s monthly maximum discharge power or single-discharge energy falls below 98% of declared values, a penalty is triggered. Four such incidents eliminate the entire month’s capacity payment; three full deductions in a year result in the loss of qualification altogether.
This directly links revenues to “dispatchability”: response speed, output stability, and actual delivered power. Inflated specifications related to capacity, efficiency, or cycle life now carry tangible financial risk.
Strategic implications for the value chain
Taken together, China’s new capacity pricing regime marks a shift from scale-first deployment toward performance-driven integration. Developers must rethink project design, prioritizing duration and efficiency aligned with local peak profiles. Equipment suppliers face rising demand for verifiable performance, longer warranties, and digital optimization capabilities. Investors gain a clearer revenue floor, but also face sharper differentiation between high- and low-quality assets.
At the system level, the policy elevates energy storage from a renewable add-on to a core reliability resource. By linking payments to peak contribution and enforceable performance metrics, Policy No. 114 aligns commercial incentives with grid needs, echoing mature capacity mechanisms in markets such as the UK, while remaining tailored to China’s centralized power system.
For China’s cleantech sector, the policy does more than improve project economics. It accelerates the transition toward a more disciplined, performance-based storage market—one in which technology choices, operational excellence, and policy design converge to support a renewables-heavy power system at the national scale.