How to Read Forecast Risk in China's Power Market Trading: Where Load and New-Energy Forecasts Enter Spot Clearing, Deviation Settlement and Assessment, the 2011 Wind-Forecast Accuracy Rules (25% Day-Ahead, 15% Real-Time, 20% RMSE), Shandong's Draft 96-Point Curves, and What Must Be Disclosed Before Bidding

Short answer. Forecast risk in China's markets is not one rule but a chain. Forecasts are clearing inputs: under the 2023 spot rules (trial), which let each province choose its market composition, day-ahead clearing works from bids under grid constraints and is to move towards bid curves plus forecast curves of non-market users; intra-day re-optimises on the latest forecasts; and reliability unit commitment uses generator bids, renewable output forecasts, inter-provincial schedules and load forecasts. Forecast error becomes money through deviation settlement and assessment: agency-purchase users' deviations settle at spot prices, with the gains or losses from stabilising residential and agricultural prices shared by all C&I users, and dispatch assesses generators for new-energy forecast deviations under provincial implementation rules. Accuracy has numeric floors for wind: day-ahead maximum error not above 25%, real-time not above 15%, whole-day RMSE below 20%, and a 75% per-point qualification threshold. Document 136 puts new-energy output in principle entirely into the market and calls for fair participation in the real-time market and faster progress towards voluntary day-ahead participation. Shandong's draft rules show the mechanics: 96-point forecast curves by 08:00, revisable day-ahead, with the short-term forecast as the day-ahead clearing cap. The 2024 disclosure rules make forecast-type information disclosable before bidding opens, with carve-outs where no spot market runs or during non-settlement trial operation, and with information classed as public, open or specific. This guide maps the chain so a trader or owner can see where the risk sits.

1. How the rules classify market risk

NDRC Order No. 20 (2024), the Basic Rules for Electricity Market Operation, applies to all electricity markets, requires each market to build a risk-prevention mechanism and assigns monitoring and prevention to market operators under 'whoever operates prevents and monitors'; its disclosure principle is 'safe, timely, true, accurate, complete and easy to use', with disclosing parties responsible for their information. The 2025 medium- and long-term rules list the risk types — supply-demand imbalance, abnormal price, unfair competition, technical-system malfunction, contract default and others — define contract-default risk as inability to perform signed contracts through loss of credit or performance capacity, disputes or force majeure, require regional risk prevention and handling plans, and size retailers', VPPs' and aggregators' bidding limits by registered assets, performance-guarantee amounts and their customers' historical consumption.

CNWattHub reading: 'forecast risk' is not a named category. It appears inside price risk (a wrong forecast means buying or selling at the wrong time), alongside contract-default risk (for a retailer, a load-forecast deviation can add procurement, deviation-settlement and liquidity pressure; whether that ends in default depends on its ability to buy in the shortfall, its funds and its contract terms, not on the forecast error alone) and inside assessment (a generator's output-forecast deviation may be assessed under the provincial implementation rules). Read each rule for the forecast it assumes.

2. Where forecasts enter spot clearing

Under the 2023 spot rules (trial), day-ahead clearing uses participants' bids under grid constraints to maximise social welfare and is moving towards clearing on market users' bid curves plus forecast curves of non-market users; the intra-day market rolls on the latest forecasts to re-optimise fast-start units; reliability unit commitment uses generator bids, renewable output forecasts, inter-provincial schedules and load forecasts; grid companies forecast agency-purchase, residential and agricultural consumption and publish it; and dispatch produces load and bus-load forecasts before bidding. The same rules list, among near-term tasks, designing mechanisms suited to new energy linked to guarantee policies, oblige generators to provide forecast operating information and give them the right to object to settlement results within set time limits.

Document 136 (2025) then puts new-energy output, in principle, entirely into the market, lets projects bid quantity and price or take the market price, calls for promoting fair participation in the real-time market and accelerating voluntary participation day-ahead, and calls for appropriately relaxing spot price limits, with the bid cap set by reference to factors including local peak C&I prices.

3. Where forecast error becomes money

• Deviation settlement. Agency-purchase users' deviation electricity is settled at spot prices, and the new gains or losses (including deviation charges) that arise from keeping residential and agricultural prices stable are shared by all commercial and industrial users.
• Assessment (考核). The 2021 grid-connection operation rules make dispatch assess generation-side entities for unplanned outages, deviations from dispatch instructions and new-energy forecast deviations under local implementation rules; regional NEA offices revise those rules and provincial offices may set different assessment and refund standards; stations must run forecasting with accuracy meeting national and industry standards.
• Real-time correction. Shandong's draft provides that when ultra-short-term load forecast deviation, new-energy output forecast deviation or unit schedule deviation leaves the system short of regulation capacity and automatic correction has not worked, dispatch operators may manually adjust intra-day load deviation, recording the event and publishing it to market members.

CNWattHub reading: the rules name the deviation but not the price. The assessment standard and refund rule are in the regional and provincial implementation rules (两个细则), which this guide did not read; obtain the current provincial version before quantifying exposure.

4. The accuracy rules

NEA's 2011 interim measures on wind-farm power forecasting define day-ahead forecasts (next day 00:00–24:00, 96 points of 15 minutes) and real-time forecasts (rolling 15 minutes to 4 hours ahead), require day-ahead maximum error not above 25%, real-time error not above 15% and whole-day RMSE below 20%, and append assessment indicators of accuracy, qualification rate (a point qualifies if, as printed, (1 − (PMk − PPk)/Cap) × 100% ≥ 75%, with Cap the farm's online capacity, 开机容量) and reporting rate; the database copy marks them as currently valid. GB/T 40607-2021 (effective 1 May 2022) specifies data, software, hardware and performance-indicator requirements for dispatch-side wind or PV forecasting systems and applies to their development, construction, acceptance and operation.

CNWattHub reading: the 2011 indicators normalise the error by the farm's online capacity (开机容量) rather than by the forecast or actual output, so the tolerance is the same absolute number of megawatts whether output is low or high.

5. Shandong's draft shows the mechanics

Shandong's July 2025 consultation draft states that new energy may volunteer for the day-ahead market and that volunteering projects currently use their short-term power forecast as the clearing upper limit; all new-energy output enters the real-time market; stations submit a 96-point forecast output curve for the operating day by 08:00 on bidding day, quantity-and-price bidders may revise it with the latest forecast, and price-takers are aggregated from same-type station forecasts and installed capacity.

CNWattHub reading: under this design, a station's own forecast caps what it can sell day-ahead; an under-forecast forgoes day-ahead volume, an over-forecast exposes the shortfall to real-time prices. Check whether your province uses the same cap.

6. What must be disclosed before you bid

NEA's 2024 Basic Rules for Electricity Market Information Disclosure cover the medium- and long-term, spot and ancillary-service markets; forecast-type information is disclosed before bidding opens and operation-type information the day after the operating day — except that where or while no spot market operates, weekly and daily information may be disclosed as operation requires, and spot-related information is not disclosed during non-settlement trial operation; information is classed as public, open (to relevant members) or specific (to particular members); market operators disclose system load, supply-demand balance, inter-provincial tie-line, total generation, non-market-unit, new-energy (by source type) and hydro output forecasts; generators disclose hydro and new-energy output forecasts. CNWattHub reading: where the operator's new-energy forecast is disclosed to a participant before bidding, the participant can compare it with its own forecast and track the operator's forecast quality over time; which class each item falls in, and whether a carve-out applies, must be checked in the province.

Reading table

Checklist

CNWattHub editorial method, not a sourced rule:

1. Obtain the current provincial implementation rules for forecast-deviation assessment and the market rules for deviation settlement; the national texts name the deviation, not the price.
2. Record your station's day-ahead and real-time forecast accuracy against the 2011 indicators (accuracy, qualification rate, reporting rate) and the provincial standard.
3. Where the operator's new-energy forecast is disclosed to you before bidding, compare it with your own and log the differences.
4. If your province caps day-ahead volume at the short-term forecast, decide the forecast bias you can afford on each side.
5. For retailers and aggregators, size bidding limits against the performance-guarantee and historical-consumption criteria the 2025 rules use.
6. Keep the settlement-objection window in mind: the spot rules give generators a set time to object.

Scope limits

One NDRC order, two NDRC/NEA basic rules (2023, 2025), one NDRC/NEA notice (2025), two NEA rules (2021, 2024), one 2011 NEA measure (database copy), one standards record and one provincial consultation draft only. No price series, forecast-error statistic, penalty rate or provincial implementation rule is quoted. Not trading or legal advice.