• Adjustment of inter-state and intra-state power

One of the main issues under consideration was the order in which inter-state and intra-state power were adjusted on pooling stations where electrical separation is not possible. The earlier regulation resulted in significantly higher DSM for the inter-state portion. RERC changed this to adjust inter-state and intra-state DSM in the ratio of such power. The order states the following:
“in case of electrical separation not being possible, then a combined schedule of inter and intrastate transaction with bifurcated interstate (with state wise bifurcation) and intrastate (with Discoms/ deemed licensee wise bifurcation) schedule shall be allowed and actual generation of the connected generators shall be considered and adjusted in the ratio of inter and intrastate schedules.” – Paragraph 247 in the order

• Billing on schedule and recovery of revenue component in DSM

The second major issue raised by the petitioners was that for inter-state power, billing on the schedule was not yet operational. This caused a problem as DSM calculations also included recovery or payment of revenue relating to the difference between the scheduled and actual generation. In its order, RERC has laid down procedures for certifying of schedules by the
SLDC – this will enable billing on schedule. However, since DSM has been made applicable from Oct 2018, the onus will now be on NVVN/ SECI to ensure that past billing on schedule is settled.

• Timelines for DSM implementation

RERC has waived off DSM charges till September 30, 2018, and has made it applicable from Oct 2018, based on the below schedule:

Similar relief has also been provided for DSM charges for inter-state power (Paras 279 A and B).?
This is a significant relief provided to generators by the honorable RERC.?
RERC further said that SLDC will be re-calculate DSM based for the above timelines till Nov 15 after which comments shall have to be submitted to SLDC in 15 days. The generators will be required to make DSM payments in one month from the issue of final bills.
“This means SLDC is directed will revise the bills towards deviation charges already issued by it and raise fresh bills on all Generators/QCA?accordingly. Bills till August 2019 shall be raised by 15th November 2019 by giving Generators/QCA 15 days for filing objections and Generators/QCA shall deposit the amount within 30 days of issue of finalized bills.”
Other than the above issues, other key points which have been discussed in the order are as follows:

• RERC rejected the request for “Aggregation” of schedules stating?

“The Commission agrees with the view of the SLDC that Aggregation at State level would result in no deviation charges for the error band of +/- 15% for such a large penetration of Renewable Energy and such magnitude would be detrimental to the stability of the Grid. This would result in a huge liability of DSM charges on the State Discoms, which will otherwise have to be passed on to the end consumers” (Para 180). RERC also deleted the clause relating to the virtual pool in the original regulations (Para 185).?
RERC has directed all generators to install check meters at RVPN GSS within 4 months (Para 191). The specifications of the new ABT meter, DCU (Data Concentrator Unit) and meter box along with Modems are available on RVPN’s website and the same is to be integrated with servers of STOMS control center at SLDC.

• 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:
Pros:

• 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.

Cons:

• 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

Conclusion:
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. ?