Central Electricity Regulatory Commission (CERC) recently published a discussion paper titled “Market-based economic dispatch of electricity: Redesigning of Day-Ahead in India”. Currently, the Indian Power Sector is characterized by various players across all segments of the value chain viz. Generation, transmission, trading & distribution. Among the 29 states, there is a total installed capacity of 346 GW (as on sept. 2018) out of which 57% is coal, 13% is hydro, 21% RE, 7.2% gas & 2% nuclear.

Most of these generations are tied up in long-term power purchase agreements with the discoms and the rest in medium-term (5 years) & short-term (1 year). At present, the discoms self-schedule generation from the portfolio to meet the majority of their daily power needs & the remaining is procured through bilateral transactions with other discoms, through power exchanges or traders.

  • Issues with the current mechanism include:
    The present mechanism under the self-scheduling process does not mandate the discoms to declare the cost of their scheduled generation or the variable cost. This causes issues like leaving several low-cost generation capacities partially or sub-optimally utilized. (Because the discoms do not have visibility of other cheaper options nor do they have a right to acquire power from generation stations they do not have a contract with) This occurs because each discom operates in its own region, known as Un-requisitioned Surplus (URS).
  • The case of sub-optimal utilization of generation assets become all the more prominent when the actual generation of each state is combined together and is contrasted with the cumulative pooled generation.
  • Given that the discoms are not obligated to reveal the variable cost of the generation that they are scheduling, true system marginal cost is not known.
  • Self-scheduling often constrains the optimum utilization of renewable sources of energy. As the visibility of a discom is limited to its own territory, surplus renewable energy in the state is curtailed.

Proposed framework – Market-Based Economic Dispatch on a Day Ahead basis

The discussion above suggests a need for optimization of scheduling and dispatch of generation capacities through suitable market design. The proposed framework known as Market-Based economic Dispatch (MBED) model will be on a day-ahead basis and schedule and dispatch all generation on the economic principles with respect to the technical constraints.

  • The main objective of the model will be to meet the system load by dispatching the least-cost generation mix while ensuring the security of the grid.
  • Ensuring that the total cost (system cost) of the generation that meets the system load in all the time-blocks for a day is minimized.

The MBED model involves primarily two following aspects viz ‘Scheduling and Dispatch’ and ‘Settlement of contacts’.

The major difference in the existing framework and the proposed MBED model is: unlike in the current framework, the discoms acquire power specifically from their contracted generators whereas, in the proposed model, the discoms would bid into the power exchange for procuring power and meeting their demand. The generators are expected to bid based on their variable/marginal cost of generation. The existing bilateral contract holders will be paid the fixed cost separately outside the market and fit in the proposed model based on their variable/marginal cost.

The price settlement scenario

Discom’s payment = Discom’s load * MCP

Genco’s revenue = Genco’s total scheduled generation * MCP

⅀ Discom payment = ⅀Genco revenue (under no transmission constraint)

Bilateral contract settlement:

Long term contracts always have a fixed price already determined in the contract. Once the power for such contracts is settled at a market-determined price, the difference will be settled between the constituents. This is generally known as a “contract for difference” and is a well-established practice in more developed power markets.

Pros & Cons of the model:


  • Better price discovery: since the entire power capacity in the country will be cleared through the market, price discovery will be more robust and more transparent.
  • Reduction of Un-requisitioned Surplus (URS): a possibility of some cheaper generation capacities not getting scheduled fully will be reduced since the process of self-scheduling will be ruled out.
  • Along with self-scheduling other challenges emanating from the practice of self-scheduling including lack of flexibility to meet seasonal and diurnal variation in demand will be brought down drastically.


  • The function of Bilateral Contract Settlement (BCS) which is introduced in the model can also increase the rates of the trade and cause disruption if a proper process is not set up.

Implementation timelines:

  • Participation will be on a voluntary basis in the initial phase
  • After a year all the discoms and other consumers will be required to participate mandatorily


Overall, the proposals outlined by CERC, when implemented will result in a radical transformation of the power markets in India. It will help eliminate inefficiencies and gaps that result from a bifurcated power sector. Like any large scale change, it will require significant preparation from all stakeholders for proper implementation, and will also take time to implement.