By the end of 2025, China's combined wind and solar capacity had reached 1.84 billion kW — 640 million kW of wind and 1.2 billion kW of solar — accounting for 47.3% of the country's total power generation capacity and, for the first time, overtaking coal. It's a landmark moment for the sector.
But for developers and investors weighing a China entry or expansion, the more consequential document from 2025 is a different one: the February 2025 notice on deepening market-based reform of renewable feed-in tariffs, widely known in the industry as "Document 136." By the end of 2025, 31 provincial-level regions (all except Tibet) had issued their own implementation rules. It doesn't change a technical standard — it changes the entire logic of whether a renewable project can make money once it's connected.
Before Document 136, renewable projects sold power at a relatively stable fixed feed-in tariff — the grid bought whatever was generated. Since the reform, renewable output is required to enter the power market and be priced through trading, with a "mechanism price" settlement layered on top as a floor. In practice, a project's revenue now has two components: market-based trading revenue, and a top-up or claw-back against the mechanism price.
As of the most recent data, roughly 86% of renewable capacity and over 80% of renewable output nationally is already priced through the market. And the mechanism-price auction results vary sharply by province — Shanghai cleared its 2026 unified auction at RMB 0.4155/kWh (against a cap of RMB 0.42), Chongqing at RMB 0.3963/kWh, both close to their respective caps, while Shandong's solar mechanism price cleared near the floor. The same 300MW project can have a materially different ten-year revenue profile depending on which province it sits in.
If market-based pricing changed how much a project earns per unit sold, consumption capacity — xiaona, or grid absorption — now determines how much it can sell at all. Solar curtailment reached 5% nationally in the first three quarters of 2025, up 1.8 percentage points year-on-year. In Q1 2026, national wind and solar utilisation stood at 91.9% and 91.2% respectively, with parts of western Inner Mongolia dropping below 90%.
The underlying cause is structural: wind and solar resources are concentrated in the northwest, while demand centres sit on the southeast coast, and ultra-high-voltage transmission build-out hasn't kept pace with new capacity. At the same time, flexible resources able to provide peak-shaving and frequency response remain limited. This is now visible directly in spot prices — during midday solar peaks, some provinces are seeing extensive negative pricing, with Shandong's negative-price share hitting 51.5% at times. A project can be technically well-connected and still lose money in certain hours.
One notable feature of Document 136 is that it explicitly prohibits local authorities from requiring mandatory storage attachment as a precondition for project approval or grid connection — correcting an earlier pattern of blanket local storage mandates. Separately, a new national policy in early 2026 (Document 114) for the first time brought grid-side independent storage into the capacity-price mechanism on equal footing with coal, gas and pumped hydro.
In effect, storage is shifting from a compliance cost into a genuine, independently tradeable revenue source — but only for developers who understand spot-price volatility well enough to actually trade around it, rather than installing a system purely to satisfy a permitting requirement. It's also worth noting that some provinces continue to raise local storage-attachment ratios (from roughly 10% toward 20% or higher) even as the national rule loosens — the gap between national policy direction and local implementation still needs to be verified project by project.
Taken together, we think a grid-connection assessment worth relying on in 2026 needs to cover three layers, not one:
Technical — interconnection point conditions, short-circuit capacity, fault-ride-through and voltage-stability requirements. This remains table stakes, not optional.
Market — the province's mechanism-price auction rules and historical clearing results, the shape of the local spot-price curve (particularly negative-price risk during solar peaks), and consumption-responsibility-weight policy. These now belong in the feasibility study, not discovered after the project is already connected.
Regulatory — local storage-attachment requirements, green power and green certificate trading rules, and cross-provincial transmission policy — all of which are still moving and need ongoing tracking rather than a one-off check.
This is also why our advisory work is structured around engineering and market strategy running in parallel: a technical feasibility study alone can no longer answer whether a project is worth building, and a market model built without real grid-access conditions is just a spreadsheet.
Wind and solar overtaking coal in installed capacity is one of the sector's most significant milestones in over a decade. Document 136's market reform marks the start of the next phase — from a race for installed capacity to a contest over consumption capacity and trading capability. For anyone evaluating or entering the China renewables market, grid-connection assessment is being redefined: it's no longer just a permit to build, but the first real test of whether a project can make money for the next ten years.
Data referenced in this article draws on public disclosures from China's National Energy Administration and the Power Planning & Engineering Institute's renewable consumption monitoring reports, along with publicly available market research. This article is for informational purposes only and does not constitute investment advice.
截至2025年底，我国风电、光伏合计装机已达18.4亿千瓦（风电6.4亿千瓦、光伏12.0亿千瓦），占全国电力总装机的47.3%，历史性地超过了火电。这是一个标志性的时间点——新能源第一次成为中国电力系统里装机规模最大的电源类型。
但对开发商和投资人来说，2025年更值得记住的，其实是另一份文件：《关于深化新能源上网电价市场化改革促进新能源高质量发展的通知》，也就是业内俗称的"136号文"。这份文件在2025年2月出台，2025年底前全国31个省市（除西藏外）陆续出台了落地方案。它改变的不是某一项技术标准，而是新能源项目从"能不能并网"到"并网之后能不能赚钱"的整个逻辑。
对于我们这样长期做电力工程与市场咨询的团队而言，2026年最大的感受是：客户找我们做并网评估时，问的问题变了。三年前，大家关心的核心问题是"这个项目能不能接入电网、需要多大的接入容量"；现在，几乎每一个新项目的评估会议上，都会多出一连串新的问题——机制电价能报多高、现货市场会不会大面积负电价、消纳能不能保证、要不要配储能。这些问题背后，是整个新能源投资逻辑的重构。
在136号文之前，新能源项目享受的是相对稳定的固定上网电价，"发出来的电，电网负责收"，这也是过去十几年新能源装机能够快速扩张的制度基础。136号文之后，新能源上网电量原则上全部进入电力市场，通过"报量报价"参与交易，价格由市场形成；与此同时，国家建立了一套"可持续发展价格结算机制"作为托底，也就是我们常说的"机制电价"，对存量和增量项目分别设置了不同的核算规则。
简单理解，新能源项目的收入现在被拆成了两部分：一部分是参与现货和中长期市场获得的市场化电价，另一部分是机制电价与市场化电价之间"多退少补"的差价结算。截至目前，发电侧约86%的新能源装机容量、超过80%的发电量已经实现市场化定价。
这套机制的落地情况，各省差异很大。以已经公布的增量项目机制电价竞价结果为例，上海2026年统一竞价出清价格为0.4155元/千瓦时（申报上限0.42元/千瓦时），重庆为0.3963元/千瓦时，均已逼近竞价上限；而山东的光伏机制电价则贴近竞价下限。这种分化直接反映了各地资源禀赋、消纳空间和市场供需的差异——同样是一个300MW的光伏项目，放在上海和放在山东，未来十年的收益模型可能完全不是一回事。
如果说电价市场化改变的是"卖多少钱"，那么消纳能力改变的就是"能卖多少电"。
2025年前三季度，全国光伏弃光率已经达到5%，同比继续提升1.8个百分点；2026年一季度，全国风电、光伏利用率分别为91.9%和91.2%，其中内蒙古西部等部分区域已经跌破90%。造成这一局面的原因并不复杂：风光资源集中的西北地区与负荷中心所在的东南沿海之间存在天然的地理错配，特高压外送通道的建设速度跟不上装机增速；与此同时，能够参与调峰调频的灵活性资源仍然不足，电网系统消纳新增新能源出力的能力已经比较紧张。
更值得关注的是价格信号已经开始反映这种压力。在光伏大发时段，部分省份的现货电价已经出现大面积负电价——山东午间光伏大发时段负电价占比一度高达51.5%。也就是说，即便项目顺利并网、顺利发电，在某些时段"发得越多、可能亏得越多"。这对项目的技术方案设计提出了新的要求：并网评估不能只算"能不能接入"，还要算清楚这个接入点、这条送出线路，在未来十年的负荷曲线和市场价格曲线下，实际能消纳多少、值多少钱。
136号文的一个重要变化，是明确不得将强制配置储能作为新能源项目核准、并网的前置条件——这在制度层面纠正了此前一些地方"一刀切"要求配储的做法。与此同时，2026年初出台的114号文，首次在国家层面将电网侧独立新型储能纳入容量电价体系，与煤电、气电、抽水蓄能"同工同酬"。
这意味着储能正在从一项"合规成本"变成一项"独立的收益来源"，但前提是项目方需要真正理解现货市场的价格波动规律，把储能当作一套交易资产来运营，而不是简单地"配一套设备应付审批"。我们也观察到，部分省份的地方性配储要求实际上仍在提高（从10%提到20%甚至更高），国家层面的政策方向与地方执行之间，仍存在需要项目方逐一核实的空间。
结合以上几点变化，我们认为一份真正有用的新能源并网评估，在2026年至少需要覆盖三个层次：
技术层面：接入点的电网条件、短路容量、故障穿越与电压稳定性要求，这是过去十年的基本功，现在依然是前提条件，一点都不能省。
市场层面：项目所在省份的机制电价竞价规则与历史出清结果、现货市场的价格曲线特征（尤其是光伏大发时段的负电价风险）、消纳责任权重政策，这些直接决定项目的实际收益，需要在可行性研究阶段就纳入测算，而不是等到并网之后才发现"电送出去了，但不赚钱"。
制度层面：地方配储要求、绿电交易与绿证政策、跨省跨区送电政策等，这些规则仍在快速变化中，各省落地节奏不一致，需要持续跟踪而不是一次性核查。
这也是为什么我们在做电力咨询时，始终坚持工程技术与市场战略"双轮并行"——单纯的技术可行性研究已经无法完整回答"这个项目值不值得投"这个问题，而单纯的市场测算如果脱离了真实的电网接入条件，也只是一份空中楼阁的财务模型。
新能源装机超越火电，是行业过去十几年最重要的里程碑之一；而136号文带来的市场化改革，则标志着行业正式进入下一个阶段——从"拼装机规模"转向"拼消纳能力和交易能力"。对开发商而言，这意味着并网评估的价值正在被重新定义：它不再只是拿到一张接入批复的"通行证"，而是判断一个项目未来十年能否持续赚钱的第一道关口。
本文数据来源包括国家能源局、电力行业规划研究与监测预警中心公开发布的新能源并网消纳情况通报，以及公开市场研究资料，仅供参考，不构成投资建议。