How to Read China's Energy Storage Investment Models: Independent vs Co-located Storage (2022 Notice), the 2026 Grid-Side Capacity Price (Based on the Coal Capacity Price, Converted by a Discharge-Duration Ratio Not Exceeding 1) and Reliable-Capacity Compensation, Charging Treated as a User with T&D Refunded on Discharge, Ancillary-Service Sharing, Inner Mongolia's 0.35 yuan/kWh Discharge Compensation and the 2025 Market Data (136 GW, 51.2% Independent, a Preliminary 1,195 Utilisation Hours)

Short answer. A Chinese battery storage model stands on four revenue legs; three are defined in national documents and the fourth is provincial. (1) Energy arbitrage: since the 2022 notice, a project with independent metering and control, dispatch-system access, legal personality and compliance with the relevant standards and market-operator requirements may convert to independent storage and trade in the medium/long-term and spot markets, and the charging energy corresponding to an independent station's discharge to the grid does not bear T&D charges or government funds and surcharges. (2) Ancillary services: independent storage is encouraged to sell balancing, emergency and fast-response services, and under the 2025 market rules it shares or receives ancillary-service costs by its on-grid (off-take) energy. (3) Capacity: the January 2026 notice lets provinces pay listed grid-side independent storage a capacity price based on the local coal capacity price, converted by discharge duration over the longest net-load peak (ratio not above 1) and determined with other factors; after the spot market runs continuously, reliable-capacity compensation is to be established in due course, and once it exists the capacity price no longer applies. (4) Provincial compensation: for example Inner Mongolia's 0.35 yuan/kWh on discharged energy for independent stations in the regional plan completed and put into operation in or before 2025. Against this, the 2026 notice treats grid-side independent storage as a user when charging and refunds T&D only on discharge, Document 136 bars mandatory storage for new renewables, and NEA-republished reporting in August 2026 still describes revenue as 'highly dependent' on spot spreads with capacity price mechanisms still needing time to land. The market was 136 GW / 351 GWh at end-2025 with a preliminary 1,195 equivalent utilisation hours.

1. The market in numbers

NEA's January 2026 press conference gives the baseline. By end-2025 China had 136 GW / 351 GWh of new-type storage in operation, up 84% on end-2024 and more than 40 times the end of the 13th Five-Year period, with an average duration of 2.58 hours. Independent storage added 35.43 GW in 2025 and reached 51.2% of cumulative capacity; lithium-ion is 96.1%. Preliminary equivalent utilisation was 1,195 hours in 2025, up nearly 300 hours (State Grid area 1,175 h, Southern Grid area 1,294 h). An August 2026 article republished by NEA quotes an NEA official that capacity had reached 153 GW / 396 GWh by end-June 2026, up 61% year on year, and reports that the 15th Five-Year new power system plan calls for about 160 GW of additions, about 80 GW of grid-side independent storage able to serve peak supply (equivalent peaking duration striving for 4 hours), and 300 GW by 2030, of which 140 GW grid-side independent storage able to serve peak supply. The 2025–2027 action plan's own target is 180 GW or more by 2027, driving about RMB 250 billion of direct project investment.

CNWattHub arithmetic: 1,195 equivalent hours ÷ 365 days ≈ 3.3 equivalent hours per day — a utilisation figure an investor should compare with the cycles assumed in the model.

2. Independent or co-located

The 2022 notice (发改办运行〔2022〕475号) created the two routes. A project 'with independent metering and control, connected to the dispatch automation system so the grid can monitor and dispatch it, meeting the relevant standards and market-operator requirements, and having legal personality' may convert to independent storage and take part in the market as an independent entity; co-located storage that completes station metering and control upgrades and meets the relevant technical requirements is encouraged to join the market together with its power source as one entity. Storage in wind-solar-hydro-thermal-storage multi-energy complementary projects is in principle not converted for now. The commercial difference is the charging cost: independent storage that discharges to the grid does not bear T&D charges or government funds and surcharges on the corresponding charging energy.

Document 136 (2025) changed the demand side of co-location: configuring storage may not be made a precondition for approving, grid-connecting or feeding in new renewable projects, and renewable energy that enters the market and is not delivered because of bidding is not counted in utilisation statistics or assessment. CNWattHub reading: the policy-driven 'mandatory co-location' market is therefore no longer a national requirement, and models for co-located storage should rest on the generator's own market economics.

3. The capacity leg: 2026 notice

The January 2026 capacity price notice (发改价格〔2026〕114号) is, among the national texts retrieved for this guide, the one that gives storage a capacity price formula, and it is conditional. Localities may grant a capacity price to grid-side independent new-type storage that serves system security and has not taken part in co-location (未参与配储). The level takes the local coal-power capacity price as its basis, converted by a ratio for peaking capability — full-power continuous discharge duration divided by the year's longest net-load peak duration, the ratio not exceeding 1 — and is determined also considering market progress, system needs and other factors. Eligible stations are managed by list; NEA sets the management requirements and provincial energy and price authorities draw up the lists.

The notice then describes the transition. After the spot market runs continuously, provincial price authorities are to establish, in due course, a reliable-capacity compensation mechanism, with compensation based on the fixed costs the marginal unit cannot recover in the energy and ancillary markets; the scope may include coal, gas and qualifying grid-side independent storage that take part in the local market, with no double compensation and none for government-priced units; and once the compensation mechanism exists, those units no longer receive the earlier capacity price. Both the capacity charge and the compensation are included in local system operation charges. The 2023 spot rules had already asked provinces to explore market-based capacity compensation linked to price caps, settlement and cost surveys, and a capacity market where conditions allow; the 2025–2027 action plan calls for improving capacity price mechanisms for storage and other regulating resources and establishing reliable-capacity compensation in an orderly way.

Two conditions in the notice bear directly on bankability. Projects for which no user affordability assessment has been done may not be planned, approved or given capacity charges or compensation. And because the conversion ratio may not exceed 1, a longer discharge duration does not raise the ratio above 1.

4. Charging, discharging and settlement

The 2026 notice fixes how pumped storage and grid-side independent new-type storage are priced at the meter. Where the spot market runs continuously, they charge and discharge at market rules or real-time spot prices; where it does not, charging is priced at the grid agency-purchase price for commercial and industrial users and the provincial price authority sets how the discharge price is formed. They are treated as users when charging — paying line-loss and system operation charges, provisionally at the T&D price of single-part energy users — and the T&D charge is refunded on discharged energy. The 2025 metering and settlement rules settle new-type storage at the level of the market participant, like any other participant.

CNWattHub reading: the 2022 exemption of charging energy from T&D and surcharges and the 2026 'user when charging, refund on discharge' wording describe the same economic result from two angles — net of round-trip losses, the energy that goes back out does not carry T&D — but the 2026 text makes the line-loss and system operation charges on charging explicit, so a model should carry them.

5. Ancillary services

The 2022 notice encourages independent storage to provide active and reactive balancing, emergency and restoration and fast active-response services, with costs shared on the principle 'who provides, who profits; who benefits, who bears', asks localities to widen peak-valley spreads appropriately according to supply and demand to make room for user-side storage, and encourages further widening of market price limits according to local conditions. The 2025 ancillary-service market rules count storage enterprises among new-type participants and have independent storage and virtual power plants share or receive ancillary-service costs by their on-grid (off-take) energy in each settlement period. The August 2026 reporting adds the caveat that 'the ancillary-service products open to new-type storage are not plentiful'.

6. What the regulator's own channel says about returns

The article NEA republished in August 2026 is unusually direct. From field research it reports that storage station operating revenue 'currently depends highly on peak-valley spreads in the energy market, is strongly affected by spot price volatility and lacks a stable revenue mechanism'; that ancillary-service products open to storage are few and 'capacity price mechanisms still need time to land'; and that some projects' siting is poorly matched to the regional grid's actual regulation needs, making 'built but unused' and 'continuous losses' likely. It quotes experts proposing a 'capacity price + energy price + ancillary services + new-business income' revenue model. CNWattHub reading: this is reporting republished by the regulator, not a policy statement, but it is the most candid official-channel description of the revenue problem a model has to solve.

7. Exit

The 2021 project management rules require owners to monitor operating status and, when a project reaches design life or no longer meets safety requirements, to assess and rectify — and, if still non-compliant, to retire the project and report to the filing authority. A model that runs 15 or 20 years should show where that gate sits.

Reading table

Checklist

1. Which route — independent or co-located — and does the project meet the 2022 technical conditions?
2. Is the station on the provincial list for a capacity price, and has the user affordability assessment been done?
3. Does the model switch from capacity price to reliable-capacity compensation once the province establishes that mechanism after spot runs continuously?
4. Are charging line-loss and system operation charges carried, with T&D refunded only on discharge?
5. Is any provincial compensation (e.g. Inner Mongolia's 0.35 yuan/kWh for planned stations in operation by 2025) limited to a cohort of projects?
6. Are assumed cycles consistent with the preliminary 1,195 equivalent hours nationally?

Scope limits

National documents of 2021–2026 plus one provincial news report are cited; no provincial tariff notice, capacity-price value, project return, spread statistic or contract is quoted. The Inner Mongolia figure comes from a Xinhua report republished by the regional energy bureau, not from the notice itself. The August 2026 article is press reporting republished by NEA. Not investment advice.