Ministry Proposes New Mechanism to Reduce Cost of Power and Renewable Curtailment
The stakeholders have time until June 30 to submit their suggestions
The Ministry of Power has issued a discussion paper on market-based economic dispatch (MBED) of power and has requested the stakeholders to provide their comments on the matter by June 30, 2021.
The ministry of power has proposed a new mechanism to bring down the cost of power for distribution companies (DISCOMs) and consumers. The power demand by all states is proposed to be met through a central pool allocating power at the optimal price. So far, DISCOMs have been sourcing power from available sources within the state, invariably ending up with a higher cost of power.
The Ministry believes that the proposed MBED mechanism would be a key step in transitioning towards ‘One Nation, One Grid, One Price”.
Considering total power generation of 1,393 billion units in the country with a weighted average power price of ₹2.36 ($0.032)/kWh, the savings from the proposed mechanism would be 3.74%, amounting to ₹122.95 billion ($1.69 billion).
The mechanism is also expected to enhance greater renewable energy integration with the balancing area increased from state to national level leading to a huge drop in renewable energy curtailment.
The paper outlines a phased introduction of MBED with Phase 1 involving the thermal fleet of NTPC to test the efficacy of the MBED mechanism from April 1, 2022.
To implement the first phase of MBED, the following are the key changes proposed to the existing practice of power procurement and scheduling:
- DISCOMS and the generators must mandatorily participate in the day-ahead market segment of power exchanges for bidding. Under the existing mechanism, DISCOMs can self-schedule the NTPC generators and access the power exchanges for the balance of their energy requirements.
- The generators will have to submit offers and be cleared based on the total demand bid in the day-ahead market. Once the bids and offers are received, the market-clearing engine will seek to optimize the dispatch of generation sources. In the existing arrangement, generators are scheduled by DISCOMs based on their declared capabilities and states’ requirements.
- The entire demand from NTPC stations will be met by dispatching the least-cost generation mix while ensuring that the grid’s security is maintained. So, cheaper NTPC projects will be dispatched to the maximum extent, whereas costlier projects will run optimally as required. Currently, DISCOMs do not have cheaper options outside the states, so several low-cost generation capacities remain sub-optimally utilized.
- The generators will be required to offer their capacities in the day-ahead market based on a self-determined energy charge rate (ECR) with no adjustments for retrospective revisions in fuel and other charges. Currently, generators are scheduled based on the merit order, which considers variable charges determined by the Commission.
- DISCOMS will be required to submit bids for all the time blocks of the upcoming day. DISCOMs may choose to submit ‘fixed demand’ in each block, which has to be served. As per the existing provision, DISCOMs communicate the dispatch schedule to regional load despatch centers (RLDCs) for their contracted generators.
- Buyers and sellers can submit bids and offers on a particular power exchange based on their mutual preference. Currently, generators declare their capabilities for the next day to the RLDCs, which then communicates entitlements to state load despatch centers (SLDCs).
- Once the bids and offers are received, the market-clearing engine of the power exchanges will schedule the generating stations following optimal despatch principles. The market-clearing prices will be discovered for each 15-minute time block of the upcoming day. As per the existing clause, the self-scheduling of generators by DISCOMs often leads to a sub-optimal merit order stack for scheduling and despatch.
- Right to Revision (RTR) for the complete fleet of NTPC projects will cease to exist until the results of the day-ahead market are announced, and such RTR will be reinstated in respect of the capacity not cleared in the day-ahead market. The existing provision says that both the generator and the DISCOM can revise their schedule seven to eight times before delivery without any financial liability.
- The DISCOMs and buyers will pay the market operator at the market-clearing price for the day-ahead demand. Similarly, all generators will be paid according to the execution of their selected bids. Currently, the DISCOMs pay the variable charges to scheduled generators based on the volume of energy scheduled.
- NTPC generators with a long-term contract will continue to be paid the determined cost separately outside the market. Currently, NTPC generators who have long-term contracts are paid the fixed cost separately outside the market.
On average, the proposed MBED implementation will yield nearly 4% of benefits in power procurement cost. The proposed MBED pilot with all the interstate generating stations (ISGS) is expected to yield benefits of more than ₹50 million (~$684,507) per day for the entitled states (Andhra Pradesh, Telangana, Maharashtra, Karnataka, and Chhattisgarh). If the entire generation in the country is mandated to participate, the total estimated savings could be to the extent of ₹122.95 billion ($1.69 billion) per year.
Some key issues
Relinquishment of ‘Right to Revise’ schedule by DISCOMs
With the implementation of MBED, the participating DISCOMs will forego the ‘Right to Revision’ schedules of the NTPC thermal projects. They may face the risk of not being able to meet demand through the day-ahead market.
To minimize the exposure and impact, the Ministry has proposed that the ‘Right to Revision’ for NTPC projects will cease to exist only for the period until the results of the day-ahead market are announced, and such Rights will be reinstated with respect to the generation capacity not cleared in the day-ahead market from these projects.
Working capital management for DISCOMS
As per the existing practice of payment for the volume of power procured, a monthly invoice for the aggregated amount of electricity sold to the DISCOM by the generator in a month gets issued in the first week of the ensuing month, and the DISCOM has 45 days from the invoice date to pay the dues. However, with the implementation of MBED, it is expected that the entire power tied up with NTPC thermal stations would be transacted on the power exchanges.
The Ministry has proposed that to ensure that DISCOMs are not burdened with such huge upfront payments, a centrally designated agency such as the Power Finance Corporation or REC could provide a line of credit to DISCOMS who require such working capital. The DISCOM could repay such amount along with interest within 45-60 days from the date of disbursement of each tranche.
Need for price coupling
The Central Electricity Regulatory Commission (CERC) regulations allow for multiple power exchanges to ensure competition in day-ahead markets; structurally, the same can continue. However, for better system efficiency, there would be a need to combine the bids and offers of both the exchanges to arrive at uniform area clearing prices and achieve higher social welfare than the sum of maximum social welfare in multiple power exchanges.
To resolve the issue, the Ministry has suggested that the buyers and corresponding sellers, based on their mutual preference, need to submit bids and offers on the particular power exchange. This would ensure that both the parties are subject to the same clearing price and liquidity.
Additional relief for DISCOMs
As per the existing mechanism, a 1.5% rebate is provided to the DISCOMs, if the payment is made to the generating companies within five days from the invoice date and a 1% rebate if the payment is made within 30 days from the invoice date.
It has been proposed that a total rebate of 2% could be offered to DISCOMs on the payment for the volume of power procured through the exchange.
Applicability of transmission charges
Currently, short-term open access charges and transmission losses are applicable for trade in the power exchange. However, the short-term open access charges get adjusted from the payment received by the generators for their cleared volumes.
The entities with long-term access should not be liable to pay the short-term charges for the volume of electricity contracted under long-term access and traded through power exchanges.
Payment of long-term charges could be adjusted against the short-term open access charges paid by the generators that have long-term access for their contracted volumes traded in power exchange.
Recently, CERC issued the draft ‘Ancillary Services Regulations, 2021’. The guidelines aim to provide power procurement through the administered process and from the spot market through power exchanges to pay for ancillary services and maintain the grid frequency close to 50 Hz.
Earlier, the Ministry of Power had decided to set up an integrated day-ahead market (DAM) at the power exchanges with separate price formation for power generated from renewable energy and conventional power.
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