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					</table>The <a href="https://powermin.gov.in/" target="_blank" rel="noopener">Ministry of Power</a> has proposed to expand the security-constrained economic dispatch (SCED) program by including more state-owned thermal projects, which would run on a day-ahead basis.
The program also intends to include intra-state thermal power stations. The objective of SCED is to minimize the total generation cost while ensuring the reliability of the power system.
SCED is a power system dispatch optimization technique used to allocate electricity generation to meet load demand while ensuring the stability and security of the system. It involves finding the most economical generation schedule while considering various constraints, such as transmission capacities, generator ramp rates, and system stability limits.
The SCED pilot project has been in operation since April 2019 with 50 inter-state generating stations with 59, 840 MW capacity whose tariffs are regulated by Central Electricity Regulatory Commission (CERC).
The pilot reduced variable costs by ₹23 billion (~$282.05 million).
Stakeholders can submit their comments and suggestions until February 22, 2023.
Benefits of SCED
The program ensures optimal resource adequacy through efficient management, even when the reserve level falls below the minimum requirement after the day-ahead markets.
SCED offers a 96-time block advance view of their expected schedule to power stations, allowing them to prepare for ramping up or down as needed in real-time operations.
The SCED program improves upon the real-time SCED dispatch, which operates on a block-by-block basis, starting two blocks before the actual operation.
The benefits of the SCED process are accumulated in the National SCED Pool Account and shared among generating stations and the states that benefit from them.
Requirements to implement the program
Implementing the program requires establishing a suitable regulatory mechanism under the draft Indian Electricity Grid Code (IEGC) 2022.
To implement the program, the day-ahead SCED requires custom software at NLDC, similar to the real-time SCED pilot. The software uses an algorithm that solves an optimization problem based on technical parameters and the merit order of energy and compensation charges.
The program’s implementation requires power plants participating in SCED to submit technical norms for unit commitment, such as start-up time, shut-down time, minimum uptime, the minimum downtime, ramp rates, etc., in the format specified by NLDC.
The program can only be implemented after at least three months after the revised IEGC is notified.
Proposed operation of day-ahead SCED
The generating stations would submit their declared maximum capacity, ramp rate, and minimum turndown level for the next day by 6:00 AM.
They would also submit the energy charge rate or compensation charge to be considered for SCED monthly.
The Regional Load Dispatch Centers (RLDC) would determine the entitlements and announce each beneficiary&#8217;s share by 7:00 AM on the day before.
The beneficiaries will then submit their requisitions or schedules from the inter-state generating stations by 8:00 AM on the day before.
Availability of resources
RLDCs will prepare the injection and drawl schedules for the power stations based on their availability and schedules submitted by beneficiaries/procurers by 9:30 AM.
The first run of the day-ahead SCED will be carried out at 9:45 AM on the day before the opening of the bidding window for the day-ahead market in power exchanges.
The schedules obtained from the SCED run will be published on the scheduling portal and are provisional at this stage.
The power stations can then participate in the day-ahead market or real-time market.
NLDC will determine the time block-wise requirement for tertiary reserves, using the output of the day-ahead SCED as one of the inputs.
Day-ahead energy market
By 1:00 PM, the bids for tertiary reserve ancillary services (TRAS)-up and TRAS-down will be consolidated and cleared by NLDC. Power exchanges will convey DAM results to NLDC after clearing the market.
Day-ahead ancillary services market
The time blocks where the cleared quantity exceeds the reserve requirement will be identified along with the shortage quantity.
The bids for TRAS-up and TRAS-down collected by the power exchanges will be consolidated and cleared by NLDC by 1:00 PM.
The shortage of reserves will be compared to the indicative reserves from the day ahead SCED run.
Ensuring adequate reserves
The NLDC will incorporate the results of the day-ahead market and the injection and drawal schedules from regional entities into the second run of the day-ahead SCED.
The inputs will be incorporated in the second run of day-ahead SCED for 96-time blocks will be done at NLDC by 5:30 PM.
If the available reserves are less than the shortfall, additional units will be instructed to start operating, and additional up reserve will be committed in order of variable cost while considering grid security, ramp rates, and impact on tie-line flows.
No additional units will be required if the available reserves are more than the shortfall.
Day Ahead SCED
The third run of day-ahead SCED for 96-time blocks will be done at NLDC after incorporating the newly committed units at 10:00 PM.
SCED schedules ensure that committed stations are scheduled with minimum turndown level while balancing load generation.
If required, the generation from on-bar stations will be reduced to maintain balance, subject to technical constraints and merit order.
The schedules provide visibility to power stations over 96-time blocks and enable them to handle ramping up or down in real time.
The SCED run in real-time (2-time blocks ahead) would further optimize the schedules after incorporating RTM results subject to security constraints.
Settlement
The settlement for day-ahead SCED involves payments from the National SCED Pool Account to the generating stations and payments to the deviation and ancillary services pool account from the stations where incremental power is scheduled. Deployment of ancillary services is settled according to the CERC Ancillary Services Regulations 2022.
Generating stations scheduled for incremental energy are paid an equivalent energy charge from the deviation and ancillary services pool account. In contrast, those scheduled for decremental energy pay back the equivalent energy charge.
SCED will help optimally maintain resource adequacy, even when the reserve situation, even after the day-ahead markets, does not guarantee minimum reserves in the system.
The commission had <a href="https://mercomindia.com/cerc-dsm-regulations/" target="_blank" rel="noopener">revised</a> the DSM framework to delink frequency and link deviation charges to the prices observed on market platforms in the day-ahead market (DAM), real-time market, and ancillary services market during a particular time slot.
The grid frequency deviated <a href="https://mercomindia.com/explainer-why-new-regulations-made-grid-unstable/" target="_blank" rel="noopener">dangerously</a> away from the acceptable range of 49.90 -50.05 Hz. It oscillated from 50.5 Hz and 49.41 Hz on December 20.

Power Ministry Proposes Expansion of Economical Power Dispatch Program

The <a href="https://powermin.gov.in/" target="_blank" rel="noopener">Ministry of Power</a> has issued guidelines to procure and utilize battery energy storage systems (BESS) as part of the generation, transmission, and distribution assets, along with ancillary services. The guidelines aim to facilitate the growth of the battery storage sector and help establish a uniform framework for all the stakeholders.
These guidelines are being issued under the provisions of Section 63 of the Electricity Act for procuring energy from BESS through competitive bidding, from grid-connected projects to be set up on a “Build-Own-Operate” or “Build-Own-Operate-Transfer” basis.
Battery storage plays a significant role in solving the intermittent nature of renewable energy. The guidelines are framed to support India in its goal of installing 500 GW of non-fossil energy. The investments in the energy storage sector have also been on the rise globally, with the total corporate funding at $17 billion in 2021 alone, according to Mercom Capital Group’s 2021 Funding and M&amp;A <a href="https://mercomindia.com/battery-storage-highest-since-2014/" target="_blank" rel="noopener">Report</a> for Storage, Grid, &amp; Efficiency.
The battery storage projects with ancillary services will help establish an independent ecosystem. Recognizing the need for such services, the Central Electricity Regulatory Commission (CERC), in its Ancillary Services Regulations, 2021, made provisions to <a href="https://mercomindia.com/cerc-proposes-energy-storage-in-maintaining-grid-stability/" target="_blank" rel="noopener">allow</a> for energy storage and demand response resources to provide ancillary services.
Ancillary services have been an integral part of the electricity ecosystem worldwide. The basic frequency and voltage control services are embedded in the electricity supply system. To enable these essential services, specific support services known as ancillary services are required to complement reliable and efficient grid operation. Ancillary services are required to maintain load-generation balance, voltage and reactive power support, and generation and transmission reserves.
The guidelines outline the bidding process for the storage projects to be commissioned across the country.
Bidding Guidelines
As per the guidelines, the earnest money deposit (EMD) must not be more than 2% of the estimated capital cost of the battery storage project. The performance bank guarantee (PBG) is set at 5% of the project cost. MNRE <a href="https://mercomindia.com/mnre-reduces-performance-guarantee-renewable-energy/" target="_blank" rel="noopener">reduced</a> the PBG amount to 3% for all renewable projects in a recent notification.
The minimum term of the battery energy storage purchase agreement (BESPA) period is eight years from the scheduled commissioning date (SCD) or the date of full commissioning of the project, whichever is later &#8211; considering the prevailing life cycle of battery systems being used without replacement. BESPA should be signed within 30 days after issuing the letter of award.
Intra-state BESS projects should have a minimum individual project size of 1 MW and above, with a suitable energy rating based on the application at one site with a minimum bid capacity of 1 MW.
Inter-state BESS projects should have a minimum individual project capacity of 50 MW and above with a suitable energy rating based on the application at one site with a minimum bid capacity of 50 MW at the minimum voltage level.
As per the guidelines, the procurer could accept part commissioning of the project if the minimum capacity for acceptance of first part commissioning will be 50% of project capacity or 50 MW, whichever is lower. For ISTS-connected projects, the minimum commissioning capacity for the first phase will be 50 MW. The total number of installments in which a project can be commissioned should not exceed three phases.
In case of project capacity up to 250 MW, the maximum timeline for commissioning projects without any liquidated damages will be 18 months from the effective date of the BESPA. While, for a project with more than 250 MW capacity, the SCD will be 24 months after the effective date of the BESPA.
The BESS Developer (BESSD) will be free to replenish the battery capacity from time to time during the BESPA duration at their cost and expense to meet the performance criteria. However, the procurer will be obligated to buy power only within the performance range as specified in the BESPA and at the charges applicable as per the existing agreements.
As per the guidelines, the BESS developer can attain the financial closure within the date, which is 12 months from signing the BESPA.
The project should be designed for inter-connection with intra (InSTS) or inter-state transmission system (ISTS) substation, either directly or through a pooling substation where other projects also inter-connect before the InSTS or ISTS substation through a transmission.
Depending on the implementation arrangements and design of the evacuation system, the capital costs of the transmission lines and substations before the InSTS or ISTS substation may either be directly paid by the BESSD or paid by the renewable energy park developer or another implementation agency and claimed from the BESSD as directly attributed or apportioned and recovered in total or as payments over the years.
The guidelines state that in cases where the procurer does not specify the project site, the responsibility of getting connectivity and grid access to the transmission system will lie with the developer. The bidding agency may provide a list of substations from which the bidders may choose the delivery points in a particular tender.
Suppose the successful bidder is a single company or a consortium. In that case, they should ensure that its shareholding in the project company executing the BESPA should not be below 51% at any time before the commercial operation date.
As per a recent NITI Aayog <a href="https://mercomindia.com/india-annual-battery-market-could-surpass/" target="_blank" rel="noopener">report</a>, India’s annual battery market could surpass $15 billion (~₹1.12 trillion) by 2030, and the battery demand is expected to rise to 260 GWh in the ‘accelerated scenario’ by 2030.

Ministry Issues Guidelines to Procure Power from Battery Energy Storage Systems

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