Nepal’s Transmission Pricing Milestone

This week, something significant happened in Nepal’s electricity market.

The Electricity Regulatory Commission (ERC) has determined, for the first time, transmission charges for third-party use of the National Transmission Grid. For FY 2026/27, the charge for Short-Term Open Access (STOA) has been set at NPR 0.57/kWh (57 paisa/unit), while Long-Term and Medium-Term Open Access are charged on a capacity basis.

What I find particularly interesting is not only the tariff itself, but the methodology behind it. The framework differentiates between LTOA/MTOA and STOA in a fairly fundamental way. 

For Long-Term and Medium-Term Open Access, the transmission charge is calculated on a capacity basis: 

Transmission Charge (NPR/MW/month) = ARR ÷ (Projected Peak Load (MW) × 12) 

For Short-Term Open Access, it is calculated on an energy basis: 

Transmission Charge (NPR/kWh) = ARR ÷ (Projected Peak Load (MW) × 8,760 × 1,000)

This distinction initially appears to create an interesting question. A hydropower plant, for example, does not operate at its maximum capacity throughout the year. If transmission charges are based on contracted capacity, a plant with significant seasonal variation could end up paying substantially more during periods when it is not actually transmitting much energy. STOA, by contrast, pays according to the energy actually scheduled under the short-term transaction.
So, does this mean STOA is being favoured?

The answer is that simple. There is a deeper regulatory rationale. First, in an emerging electricity market such as South Asia, short-term trading is important for balancing and optimizing temporary surpluses and deficits. These can occur in situations where generators need to sell power quickly. That is quite different from LTOA and MTOA, where the user may sell electricity over a longer period of time with proper strategy and negotiation. So, STOA may be seen as a different product altogether.

Second, STOA should not be confused with a short-term PPA. A short-term transaction may use STOA, but a generator or buyer seeking assured transmission access for recurring transactions over a longer period may need MTOA or LTOA. In other words, the duration of the electricity transaction and the duration/firmness of transmission access are related, but they are not the same regulatory construct.

Third, there is an important trade-off in access priority. Under the open-access framework, LTOA receives the highest allocation priority, followed by MTOA and STOA. In the event of transmission constraints, STOA customers are curtailed first. So the lower energy-based charge for STOA also comes with lower certainty of access.

As the Nepalese electricity market develops, actual transaction patterns will provide evidence about whether the distinction between LTOA, MTOA and STOA is working as intended. If particular provisions create unintended incentives or opportunities for gaming, the regulatory framework should evolve accordingly.

For me, this is one of the more interesting aspects of Nepals transition toward an open, competitive and more flexible power market: the challenge is not simply to calculate the right tariff, but to design tariff structures that align cost recovery, firmness of access, market flexibility and efficient use of the transmission network.

The transmission pricing approach adopted at this stage is essentially a postage-stamp methodology. It is simple, transparent and relatively easy to administer, although it has inherent limitations. This is a conscious and understandable choice for a country like Nepal, where the practice of pricing transmission services for third-party access is still at an early stage. The regulatory breakthrough of introducing transmission charges has, however, also raised an important question: why should the price of transmission not reflect the distance over which electricity is wheeled, rather than only the volume of power or energy wheeled?

This is a valid question. But a national transmission grid is a meshed network, and electricity does not necessarily flow from Point A to Point B along a single, identifiable path. The actual physical flow depends on the configuration and electrical characteristics of the entire network. Moving towards a more granular, distance- and network-use-based transmission pricing methodology would therefore require not only a more sophisticated regulatory framework, but also robust technical modelling, metering, data systems and specialised human resources. Nepal will eventually need to move in that direction as its electricity market becomes more sophisticated. But regulatory frameworks, like markets themselves, do not have to solve every problem on day one. For now, Nepal has reasonably chosen simplicity and administrability; over time, greater granularity and cost-reflectivity can follow.

More importantly, Nepal has now reached a point where the cost of transmitting electricity must become part of the economics of developing and operating generation projects. There has understandably been some concern that the newly introduced transmission charge could affect the viability of projects, particularly smaller hydropower projects. But this is precisely where we need to change the way we think about electricity infrastructure. Transmission is no longer merely the infrastructure between generation and consumption; it is becoming an explicit component of the economics of Nepal's power market.

If a hydropower project is commercially viable only when the cost of transmitting its electricity is assumed to be zero, we should perhaps ask a more fundamental question: was the project economically viable in the first place? The transmission charge does not create the underlying cost of using the network; it makes that cost visible. In that sense, the tariff determined by the Commission is not simply an administrative burden imposed on a project—it is, to a significant extent, a mechanism for discovering and allocating a cost that already exists in the electricity system. Open-access users will now bear this cost explicitly, whereas under the traditional single-buyer model, many of these costs were embedded within the broader economics of NEA's system.

And there is an important point that should not be lost in this debate: there is no free meal in electricity. Someone ultimately pays for the transmission infrastructure, its operation and maintenance, system losses, augmentation and the capital invested in the network. The fact that a generator did not previously receive a separate transmission bill did not mean that transmission was free. The current framework simply makes a portion of that cost visible to those who use the network under open access. Moreover, the current charge is based on the average revenue requirement of the transmission system; it is not a special cost created for a particular open-access transaction.

This is an important shift in Nepal's electricity market. Generation projects can no longer be assessed only by looking at generation cost and PPA revenue. Location, evacuation infrastructure, transmission availability, congestion and the cost of accessing the market will increasingly form part of the investment decision. That may make some projects less attractive, but that is not necessarily a flaw in the market. It may actually be the market revealing the true economic cost of delivering electricity to where it is needed.

Under the old single-buyer model, that information was much less visible. As Nepal moves towards open access and a more competitive electricity market, it is both inevitable and desirable that these costs become part of the commercial calculus.
Electricity may be abundant, but getting electricity to the market is not free.

Koirala is a consultant in electricity regulatory, policy and market matters.