Since the third regulatory period, a significant change has taken place in the provincial grid’s transmission and distribution (T&D) pricing system: the loss costs previously embedded in T&D rates have been separated out and now appear as “grid-interface loss costs,” billed to end-users as a distinct line item. But simply “separating them out” is only the first step. Understanding what this means for provincial grid operations requires clarity on several key questions.
Which Segment of the Grid Does “Grid-Interface Loss” Cover
The name “grid-interface loss cost” can create a natural intuition: is it only calculating losses after power leaves the plant and enters the high-voltage transmission network? Some might further assume it applies only to 220 kV and above—the main transmission grid—excluding distribution-level losses.
The current T&D pricing mechanism tells a different story. “Grid-interface” here describes where the cost sits within the rate structure; it does not mean the physical loss scope covers only the first segment after grid connection. Provincial grids still use a comprehensive loss rate. In principle, any reasonable energy loss caused by transmission, transformation, and distribution within the public network boundary of the grid enterprise falls within the comprehensive loss category.
Conversely, plant-use electricity and dedicated line losses within a power plant’s own property boundary, or losses occurring before the grid property demarcation point, should not simply be计入 (included in) the provincial public grid’s comprehensive loss rate and spread across all users.
Loss Costs Are Essentially Additional Power Procurement Costs
Put in physical terms, the logic is straightforward. Suppose an end-user ultimately consumes 100 kWh. Because energy is lost during transmission from the generation side to the user side, the generation side must actually inject more than 100 kWh into the system.
If the comprehensive loss rate is 5%, using common reverse-calculation methods, the required generation-side injection is: 100 ÷ (1 − 5%). The portion exceeding 100 kWh—that is the electricity that must be additionally procured to compensate for network losses.
So loss costs, fundamentally, are not a traditional “network service fee.” They are closer to: the cost incurred from procuring extra energy to compensate for physical losses. This is also why, since the third regulatory period, loss costs have been separated from T&D rates—because T&D rates mainly address the grid enterprise’s allowable revenue recovery, while loss costs correspond to a procurement cost that fluctuates with energy market prices.
Most Regions Still Rely on Unified Grid Procurement
Reviewing publicly available agency procurement price tables and settlement rules across provinces, most regions’ loss electricity is still uniformly procured by the grid enterprise on behalf of users.
Two approaches can be seen. The simpler one: both market-based users and grid-agency procurement users apply the same grid-interface loss discount rate. The grid centrally procures loss electricity and establishes a uniform loss cost standard, implemented by relevant commercial and industrial users.
A more refined approach: different users calculate loss costs according to their own actual power purchase prices. Grid-agency users compute based on the month’s published agency procurement price; market-based users compute using their own market-based power purchase price combined with the same comprehensive loss rate.
Thus, even when everyone applies the same certified loss rate, the final loss costs may differ. The underlying logic is simple: if User A buys electricity at a lower price in a given month and User B at a higher price, the loss electricity generated alongside their respective consumption should also carry different costs.
Xinjiang: Loss Electricity Directly Enters User Settlement
Xinjiang’s approach warrants closer attention. Actual market settlement statements show that retail users’ final settlement electricity is not limited to what the meter records. In addition to actual consumption, the published comprehensive grid-interface loss rate is used to reverse-calculate corresponding loss electricity.
In other words: Actual consumption + Loss electricity = Final settlement electricity
More interestingly, this loss electricity and the user’s actual consumption are priced at the same market rate. If a user’s monthly market-based power purchase price is P and the comprehensive loss rate is r, the corresponding loss discount can be expressed as: P × r ÷ (1 − r).
This means Xinjiang’s market-based users’ loss costs are now directly tied to their own actual procurement prices. Cheaper electricity this month means loss electricity is also settled at a lower price; more expensive means loss costs rise synchronously.
From an economic responsibility standpoint, this goes further than “all market users apply the same uniform loss discount.” However, a careful distinction is needed: loss electricity entering market-based user settlement does not necessarily mean sellers proactively bought extra electricity in the month-ahead market. It could be that normal electricity was procured during the trading phase, and at the settlement stage, loss electricity is reverse-calculated based on actual usage and the certified loss rate, treated as settled at the same price.
The more accurate statement is: Xinjiang has achieved relatively clear market-based settlement of loss electricity and user-price-based cost allocation.
Certified Values and Actual Values Cannot Fully Align
Regardless of which method is used, as long as a certified comprehensive loss rate is applied, one problem is inevitable: certified values and actual values cannot stay perfectly aligned over time. Differences arise from at least two sources.
One is quantity—the gap between loss electricity procured based on the certified rate and the loss electricity actually incurred during grid operations. The other is price—the loss discount formed ex ante may differ from the actual price paid when procuring this electricity ex post.
This creates: grid-interface loss agency procurement surplus/deficit. From the current handling approaches in most regions, such surpluses or deficits ultimately still need to be allocated among or shared by relevant commercial and industrial users.
The Significance of Certified Loss Rates Differs for System Total Cost vs. Individual Users
If a complete loss agency procurement surplus/deficit clearing mechanism exists, then from a system-wide perspective, whether the certified loss rate is 4%, 5%, or slightly higher or lower, its impact on final total cost diminishes. Because what end-users ultimately bear is the actual incurred loss procurement cost.
If the certified value is high, more is collected ex ante and returned later through surplus sharing; if low, less is collected and made up later through deficit allocation. From the system total cost perspective, the certified comprehensive loss rate increasingly functions as an ex ante preliminary settlement parameter.
But for individual users, it still matters significantly. Because surpluses and deficits are not cleared in the same month they arise. If N+2 or later-month rolling treatment is adopted, ex ante charges and ex post allocations do not occur on the same batch of electricity, the same batch of users, or the same month.
During the interim, user consumption scales may change, market entities may enter or exit, and electricity structures may shift. Thus, even if the system total cost ultimately achieves a closed loop, the amount borne by each individual user may not fully equal the loss cost corresponding to their original consumption.
Therefore, the certified loss rate still affects: current electricity bill levels, user capital occupancy, monthly price volatility, interperiod cost allocation, and fairness of allocation among different users.
If Users Bear Loss Costs, Why Should Grids Still Work to Reduce Loss
At this point, a more fundamental question naturally arises. If reasonable loss electricity is ultimately paid for by users; if the gap between ex ante certification and ex post actuals can be allocated or shared through loss agency procurement surplus/deficit mechanisms; then from the perspective of a provincial grid enterprise’s own interests: does it still have the incentive to continuously reduce internal grid losses?
In reality, we do indeed see grid enterprises continuing to carry out same-period loss governance, transformer area management, metering governance, anti-theft measures, reactive power optimization, and distribution network technology upgrades.
This demonstrates: who bears the loss cost and who bears loss efficiency responsibility are not the same question. Price mechanisms can allow reasonable loss costs to be borne by users. But whether grid enterprises, as natural monopolies, have a responsibility to continuously reduce losses that can be improved through management and technical means is a separate regulatory issue.
Especially since the current T&D price supervision rules clearly stipulate: the certified comprehensive loss rate must not exceed that of the previous regulatory period. This means losses are not simply “pass through whatever is incurred to users.” Regulatory institutions continue to impose efficiency constraints on grid enterprises.
So the question worth discussing next has shifted from “how loss costs are calculated” to: while users can bear reasonable loss costs, must grid enterprises still bear the responsibility for continuous loss reduction?
Source: China Energy News Network, BJX Power Network
Original URL: https://news.bjx.com.cn/html/20260918/1513424.shtml