power-market-trading-docs/primers/grid/03_china_electricity_markets_en.md

China's Electricity Markets: A Primer

How the world's largest power system is building markets — the history from plan to price, the players, the layered market architecture, the 2025 reform wave, and the road to a unified national market.

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Introduction: the largest system, the youngest market

China runs the world's largest power system by every measure — capacity approaching 4 TW, consumption near 10,000 TWh — yet its electricity markets are among the youngest of any major economy. For most of its history, Chinese electricity was not priced at all in any economic sense: it was allocated. Plants received administratively set tariffs and administratively allocated operating hours; users paid catalog prices set by the state. The past decade has been a deliberate, cautious, and now rapidly accelerating effort to replace that machinery with markets — while never letting go of the state's grip on reliability, affordability, and industrial strategy.

Understanding China's markets requires holding two ideas at once. First, the direction is unmistakably toward markets: by 2025, spot markets were mandated to cover essentially the whole country, and all new wind and solar must sell through the market. Second, the philosophy differs from the Anglo-American one: prices in China have traditionally been treated as cost-recovery instruments to be stabilized, not scarcity signals to be unleashed. Every reform is a negotiation between those instincts. The result is a hybrid unlike anything in the US or Europe — and given that China's grid is three times the size of America's, this hybrid is quietly becoming the most consequential electricity market design experiment in the world.

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Chapter 1 — From plan to market: the reform arc

1.1 The monopoly era and the 2002 separation

Until 2002, a single entity — the State Power Corporation, heir to the Ministry of Electric Power — owned nearly everything. The foundational reform of 2002 (State Council Document No. 5) broke it apart along one axis: separating plants from the grid (厂网分开). Generation assets were distributed among five major state-owned generation groups (Huaneng, Datang, Huadian, Guodian, and China Power Investment — later consolidated and joined by others), while the wires went to two grid companies: State Grid Corporation of China covering ~88% of the territory, and China Southern Power Grid covering five southern provinces. Crucially, the 2002 reform stopped there: the grid companies remained the sole buyer and sole seller of electricity, purchasing from plants at regulated on-grid tariffs and selling to users at regulated catalog prices, with dispatch run administratively from inside the grid companies themselves.

1.2 The administrative market (2002–2015)

The next decade ran on two administrative pillars. Benchmark tariffs: each province had a regulated on-grid price for coal power (the "coal benchmark"), with renewables later receiving feed-in tariffs pegged above it. Fair dispatch (三公调度): rather than merit order, plants of the same class were allocated roughly equal annual operating hours — equitable among state-owned peers, but economically blind, keeping inefficient plants alive and giving no reward to flexibility. Pilot "direct trading" between large users and generators appeared, but the system remained fundamentally a plan.

1.3 Document No. 9 (2015): the modern reform charter

The March 2015 "Opinions on Further Deepening Power Sector Reform" (中发9号文) launched the current era with a memorable formula: "control the middle, liberalize the two ends" (管住中间、放开两头). Transmission and distribution would remain regulated monopolies with cost-audited tariffs; generation prices and retail would be progressively opened to competition. The document spawned the institutions of today's market: provincial power exchanges, independent(ish) trading platforms, thousands of registered retail companies, and — from 2017 — the first batch of provincial spot market pilots (Guangdong, Shanxi, Shandong, Zhejiang, Gansu, western Inner Mongolia, Sichuan, Fujian).

1.4 The 2021 shock and the great liberalization

In late 2021, surging coal prices collided with capped power tariffs; generators lost money on every MWh and power rationing spread across provinces. The crisis forced the boldest pricing move yet: in October 2021, all coal-fired generation was pushed into market trading, with prices allowed to float ±20% around the benchmark (no upward limit for energy-intensive users), and regulated catalog tariffs for all commercial and industrial users were abolished — pushing effectively all C&I consumption into the market. Residents and agriculture kept protected prices. In one stroke, market-traded volume jumped to well over 60% of consumption.

1.5 The construction decade: 2022–2026

The subsequent policy cadence has been relentless:

• 2022, Document No. 118 territory: the NDRC/NEA blueprint for a unified national power market system — a multi-layer design of national, regional, and provincial markets, initially targeted to be preliminarily established by 2025 and basically complete by 2030.
• 2023: national trial Basic Rules for the Electricity Spot Market standardized the spot design; Shanxi and Guangdong graduated from years of trial settlement to formal spot operation; and a capacity payment for coal power was introduced from 2024 — explicitly recasting coal as a backup and balancing resource paid for availability rather than volume.
• 2024: the overarching Basic Rules for Power Market Operation took effect, the first regulation covering the whole market architecture.
• 2025 — the reform's biggest year: February's Document No. 136 pushed all new wind and solar into market trading with a CfD-style settlement mechanism (Chapter 4); April's spot-market notice ordered essentially nationwide spot market coverage by the end of 2025, with named deadlines for each province; the first national Basic Rules for the Ancillary Services Market standardized products and introduced beneficiary-pays cost allocation; and mandatory storage-pairing requirements for renewables were abolished.
• 2026: the State Council set the goal of a unified national market basically established by 2030 and fully established by 2035, confirming both the direction and the realism about pace.

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Chapter 2 — The players

2.1 The state

NDRC (National Development and Reform Commission) is the super-ministry: it owns pricing policy (through its price bureau), approves major reforms, and issues the numbered documents that structure the entire sector. NEA (National Energy Administration), nominally under NDRC, handles energy planning, market rules, licensing, and supervision, with regional bureaus overseeing market conduct. There is no independent regulator on the FERC model: the referee is also the planner and part-owner of the teams.

Provincial governments are arguably the most underrated players. Electricity reform in China is implemented province by province; provinces set local market rules within national frameworks, run their own exchanges, own stakes in generators, protect local industry through electricity pricing, and historically resisted imports that would idle local plants. The "provincial fortress" problem — balkanized markets that trap cheap power inside borders — is the central obstacle the unified-market program exists to break.

2.2 The grid companies

State Grid and Southern Grid are unlike anything in Western markets: state-owned giants that own the wires, run the dispatch centers (there are no independent ISOs — dispatch sits inside the grid companies), operate the two national-level trading platforms through their affiliates (the Beijing Power Exchange Center for the State Grid area, the Guangzhou Power Exchange Center for the south, handling inter-provincial trade), and historically earned the spread between regulated purchase and sale prices. Reform has converted their regulated revenue to audited transmission-distribution tariffs and forced trading functions into somewhat more independent subsidiaries, but the structural conflict — the market operator, system operator, and largest commercial actor sharing one balance sheet — remains the deepest governance difference from Western designs.

2.3 The commercial cast

Generation is dominated by large state-owned groups — the central-government "Big Five" (now reorganized around Huaneng, Datang, Huadian, SPIC, and CHN Energy from the Guodian–Shenhua merger) plus nuclear specialists (CGN, CNNC), the Three Gorges group in hydro, provincial energy groups, and an enormous, genuinely diverse renewables sector including many private developers. Retail companies number in the thousands since 2015, though most are thin intermediaries reselling MLT contracts; grid companies still serve residents and act as default supplier. Users: all commercial and industrial consumers are in the market; large industrials increasingly trade directly and sign green PPAs. And uniquely, the carbon market (national ETS) sits alongside: covering the power sector since 2021 with intensity-based free allocation, it prices coal plants' emissions and interacts (still weakly) with power prices.

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Chapter 3 — The market architecture

China's wholesale market is a layered stack, dominated by contracts, with spot markets as the new foundation being slid underneath.

3.1 Medium- and long-term contracts: the backbone

Unlike US markets where day-ahead auctions anchor everything, China's system is built on medium- and long-term (MLT) contracts — annual, quarterly, monthly, and now intra-month bilateral and centrally-listed trades that historically covered around 80% of market volume, and which policy still requires to cover the large majority of most participants' positions (a stability mandate: the MLT book is the shock absorber that keeps average prices anchored). Reform is making MLT progressively more spot-compatible: contracts are decomposing from flat monthly blocks into time-of-use and even hourly-shaped positions that settle as differences against spot prices — converging on the international model of financial contracts layered over a physical spot market.

3.2 Provincial spot markets: the new foundation

The spot design that emerged from the pilots is broadly uniform: centralized day-ahead and real-time markets at 15-minute granularity, security-constrained dispatch, with a characteristic pricing asymmetry — generators are paid location-based prices while load pays a uniform provincial price. In effect: nodal or zonal on the supply side, single-zone on the demand side — a design closer to Europe's zonal markets than to US nodal LMP, but with locational granularity on generation that Europe lacks.

Shanxi and Guangdong were first into formal continuous operation (December 2023), followed by Shandong and a lengthening list; the April 2025 acceleration notice set province-by-province deadlines — a group including Hubei and Zhejiang to reach formal operation by end-2025, sixteen more provinces to enter continuous trial settlement, and the southern region to push cross-provincial mechanisms — amounting to a mandate for effectively nationwide spot coverage by the end of 2025. Spot prices are bounded by provincial caps and floors (Jiangsu, for example, caps offers at ¥1.5/kWh with a floor of ¥0 for most trading, while several provinces allow negative prices — Zhejiang's pilot saw −¥0.18/kWh during peak solar hours, and Shandong has recorded extended negative-price episodes during holiday solar floods).

3.3 Inter-provincial and regional markets

Cross-border trade runs on a separate track: government-framework agreements and grid-to-grid contracts underpin the big west-to-east UHV flows, supplemented by the Beijing exchange's inter-provincial spot market for surplus renewables — a mechanism that lets otherwise-curtailed wind and solar find buyers across provincial lines — and by the southern regional market, which extended Guangdong's spot trading toward a five-province regional design and stands as the prototype for multi-province market operation. Regional spot markets launched trial operations in late 2024. This layer is where the unified national market will be won or lost: over 80% of traded volume remains intra-provincial, transmission rights and pricing between provinces are still rigid, and exporting provinces retain strong incentives to serve local industry first.

3.4 Green power, certificates, and carbon

Three environmental-value markets coexist. Green electricity trading (since 2021) lets users buy renewable MWh bundled with their green attributes at a premium, mostly via MLT contracts — the Chinese green PPA. Green Electricity Certificates (GECs) are the unbundled instrument, now issued for essentially all renewable generation and increasingly demanded by exporters facing carbon border adjustments and by sectors under new renewable-consumption mandates (steel, cement, polysilicon, and some data centers must cover set shares of consumption with renewables). The national ETS prices carbon intensity for the power sector. Coordination among the three — avoiding double-counting, aligning incentives — is an active reform frontier.

3.5 Ancillary services and capacity

Ancillary services markets (frequency regulation, reserves, ramping) developed province by province, with a peculiarity: costs were historically shared among generators rather than passed to load. The 2025 national basic rules standardize product definitions and shift toward beneficiary-pays allocation, folding ancillary costs into user tariffs as spot markets mature — and opening participation to storage, virtual power plants, and demand response. On capacity: rather than auctions, China uses administered capacity payments — two-part tariffs for pumped hydro (around ¥500/kW-year), the 2024 coal capacity payment (a set fraction of a reference fixed cost, stepping up over time), and, functionally, the Document 136 mechanism price for renewables — an emerging suite of availability-based payments that substitutes for a capacity market, with the trade-off that prices are set by regulators rather than discovered by auction.

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Chapter 4 — Pricing mechanics

4.1 The coal benchmark and the band

The anchor of Chinese power pricing remains the provincial coal benchmark tariff, a legacy administered price now serving as the reference point for the market band: coal power trades within ±20% of benchmark (uncapped upward for energy-intensive industries). MLT prices, spot caps, and even renewable mechanism prices are all expressed and negotiated relative to this anchor. It is a deliberately bounded market — enough room for meaningful price formation, not enough for politically intolerable outcomes.

4.2 Time-of-use and the retail link

Since C&I catalog tariffs were abolished, business users pay market-based energy costs plus regulated transmission-distribution tariffs, system charges, and surcharges. Provincial time-of-use schedules — with peak/valley ratios often 3:1 or wider, and deep-valley periods added around midday solar — remain administratively set but are progressively being aligned with (and in spot provinces, superseded by) actual spot price shapes. Residential and agricultural users stay on protected catalog prices, sustained by cross-subsidy from C&I users — one of the system's most guarded political settlements and a growing tension as industrial users gain the option to procure efficiently.

4.3 Document 136: renewables meet the market

The February 2025 reform (formally the "Notice on Deepening Market-Oriented Reform of On-Grid Tariffs for New Energy") is the pivotal renewables policy of the decade. Its content:

• All new wind and solar output enters market trading — ending the era of guaranteed offtake at fixed prices, which still covered roughly half of renewable generation when the policy landed.
• In its place, each province operates a sustainable pricing settlement mechanism (机制电价): a two-way contract-for-difference. Projects receive a strike ("mechanism") price for a covered share of their output; when market prices settle below it, they are topped up; when above, they refund the difference.
• Existing projects (pre-June 2025) transition at prices capped by the coal benchmark, preserving legacy economics. New projects must win their mechanism price in annual competitive auctions, with volumes linked to provincial renewable-consumption quotas and prices capped at the coal benchmark.
• Unlike European CfDs that typically cover all output, Chinese provinces underwrite only a portion — commonly 40–80% of generation — leaving the remainder fully exposed to market prices.
• The same document abolished mandatory storage-pairing for new renewable projects, replacing an administrative burden with market incentives (widened peak-valley spreads plus provincial capacity compensation have made standalone storage economic in several provinces).

Early auctions delivered a cold shower: Shandong's first round cleared wind at ¥0.319/kWh but solar at just ¥0.225/kWh — below what many believe is financeable — while Yunnan set ¥0.33 for both. The policy triggered a historic installation rush before the June 2025 cutoff, followed by a market-digesting slowdown. The design's known gaps: annual price-setting versus multi-decade project economics, and no protection against curtailment (the CfD pays only for power actually delivered).

4.4 What spot prices are revealing

Where spot markets run, they are doing exactly what theory predicts: midday prices collapse (and go negative) under solar floods; evening peaks widen; peak-valley spreads have expanded sharply in high-renewables provinces; flexible coal, storage, and shiftable demand are being paid for what they actually provide. Average full-load hours of large plants fell notably in 2025 — the statistical signature of a system pivoting from volume to flexibility.

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Chapter 5 — The system's distinctive logic

5.1 The dual track

China runs market and plan simultaneously and deliberately. Priority-purchase categories (residential, agricultural, some public-interest and legacy contracts) sit outside the market; provincial planners still issue annual generation guidance; inter-provincial framework agreements predate and constrain market trade. The dual-track is shrinking but is a feature, not a transition artifact: it is how reformers ring-fence the politically untouchable while marketizing the rest.

5.2 Provincial fortresses

The signature pathology. Provinces are fiscal and political units whose governments answer for local growth, employment, and energy security; a governor gains little from importing cheaper power that idles local plants and taxable industry. The resulting barriers — rigid annual export/import plans, preferential local dispatch, resistance to transmission-capacity release — are why central documents now use pointedly muscular language about "breaking provincial barriers," why regional markets are being pushed hard, and why the unified national market timeline has repeatedly stretched.

5.3 Consumption mandates and curtailment

The renewable portfolio standard analog is the renewable consumption responsibility weight (消纳责任权重): annual provincial quotas for the share of consumption met by renewables, cascaded to grid companies and users, now extended to specific industries. Quotas, GECs, mechanism-price volumes, and green trading all interlock through this instrument. It exists because of curtailment: with capacity growing faster than local demand and export capability in the northwest, curtailment rates in the worst pockets (parts of Gansu and neighboring regions) have climbed above 30% for solar — the system's clearest signal that integration, not installation, is the binding constraint.

5.4 Dispatch and the philosophy of price

The deepest transformation is conceptual. The old system dispatched administratively and treated price as a cost-recovery formula; the new one lets security-constrained economic dispatch replace fair-hours allocation wherever spot markets formally operate, and asks prices to coordinate behavior — while regulators still visibly flinch at volatility, bounding every market with caps, floors, bands, and mechanism prices. China is adopting the machinery of price signals while retaining the instinct of price control; how far the second yields to the first is the single best question to ask of every future reform document.

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Chapter 6 — China vs. the US: the same physics, opposite architectures

Dimension	United States	China
Market coverage	~2/3 of load in RTO markets; rest regulated	All C&I in market; residents/agriculture protected
Anchor market	Day-ahead auction (spot-centric)	MLT contracts (~80%), spot layering in beneath
Spot design	Nodal LMP both sides	Location-based for generation, uniform provincial price for load; 15-min
System operator	Independent ISOs/RTOs	Dispatch inside the two grid companies
Regulator	Independent (FERC) + states	NDRC/NEA (planner-regulator) + provinces
Capacity adequacy	Auctions (PJM), scarcity pricing (ERCOT), obligations (CAISO)	Administered capacity payments + mechanism prices
Renewables support	Tax credits + markets + state policies	FiT era → Document 136 CfD auctions + consumption quotas
Congestion between regions	Priced (LMP), hedged (FTRs)	Largely administered; framework agreements + emerging inter-provincial spot
Core constraint	Building supply (queues, permitting)	Absorbing supply (integration, provincial barriers)
Price philosophy	Scarcity signal	Cost-recovery instrument, cautiously liberalizing

The two systems are converging from opposite directions: the US is re-learning planning (transmission mandates, fast-track procurement, capacity interventions) while China is learning prices (spot markets, CfDs, beneficiary-pays). Each is adopting precisely the tool the other's crisis proved necessary.

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Chapter 7 — Trajectory and open questions

The official roadmap now reads: nationwide provincial spot coverage (essentially achieved on paper at end-2025), regional markets deepening from the southern prototype, a unified national market basically established by 2030 and fully established by 2035, with inter-provincial trade and renewable allocation as its stated core purpose. The open questions that will define whether the blueprint becomes reality:

1. Will provinces yield? Everything depends on whether transmission access, dispatch, and settlement rules genuinely erode provincial fortresses, against entrenched local interests.
2. Can renewables finance on auctioned CfDs? If mechanism prices keep clearing below financeable levels (as early solar auctions suggest), either designs adjust, costs fall further, or the buildout slows toward the ~200 GW/year pace implied by the 2035 target of 3,600 GW.
3. Who pays for flexibility? The suite of administered capacity payments (coal, pumped hydro, storage compensation, mechanism prices) must eventually cohere — or be replaced by scarcity pricing regulators have so far resisted.
4. Will an independent operator emerge? A genuinely unified market strains the model of dispatch and trading inside the grid companies; whether China creates something ISO-like is among the most consequential institutional questions.
5. Demand as a resource: spot price signals are only now reaching commercial users; virtual power plants, storage, and flexible industrial and computing loads are the designated growth area of the next Five-Year Plan.

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Quick-reference glossary

Term	Meaning
Document No. 9 (2015)	The charter of the current reform round: "control the middle, liberalize the two ends"
Document No. 136 (2025)	All new renewables into the market; CfD-style mechanism price via provincial auctions
Mechanism price (机制电价)	The CfD strike price covering a share of a renewable project's output
MLT	Medium- and long-term contracts, the dominant trading layer
Coal benchmark	Provincial reference tariff; market prices float ±20% around it
Consumption responsibility weight	Provincial renewable-consumption quota (China's RPS analog)
GEC	Green Electricity Certificate, the unbundled renewable attribute
Fair dispatch (三公调度)	The old equal-hours administrative dispatch, being replaced by economic dispatch
Provincial fortress	Provincial protectionism fragmenting the national market
Beijing / Guangzhou PX	The two inter-provincial power exchange centers (State Grid / Southern Grid areas)
Capacity payment	Administered availability payments (coal from 2024, pumped hydro two-part tariff)
Unified national market	The 2030 (basic) / 2035 (full) goal: national-regional-provincial multi-layer market
ETS	The national carbon market, covering power since 2021

End of primer.