Opinion on AERC (Framework for Resource Adequacy) Regulations, 2024 [Draft]

Assam Electricity Regulatory Commission notified draft regulations on Framework for Resource Adequacy (RA) on 06th September, 2024. The key highlights of this draft document are mentioned below:

Objective: The framework emphasizes the need for distribution licensees to optimize power procurement planning to support RE integration and maintain system reliability. Additionally, the draft regulation states that discoms must maintain a minimum of 70% of their long-term contracts, 20% from medium-term, and the remaining from shortterm contracts. During the power procurement planning, discoms must consider the impact of RPO, demand side management, energy efficiency programs and energy conversation programs. Furthermore, the State Load Despatch Centre and discoms are directed to provide 10-year demand forecasts to relevant government agencies for conducting Resource Adequacy Planning (RAP).

OERC (Framework for Resource Adequacy) Regulations, 2024 [Draft]

Odisha Electricity Regulatory Commission notified draft regulations on June 2024 on “Framework for Resource Adequacy” (RA). The key highlights of this draft document is mentioned below:

Objective: The sole objective of Resource Adequacy framework is the reliable fulfilment of the peak demand with the help of adequate supply of generation and demand response.
The Resource Adequacy framework will cover the following important aspects:
a) Availability of adequate generation capacities to reliably serve demand under multiple scenarios.
b) Optimal capacity mix based on minimization of overall system cost.
c) Time horizon for the implementation of the framework should be 5 – 10 years.
d) Energy storage, other flexible resources, and short-term sale/purchase under bilateral contracts will be incorporated into the resource adequacy framework.

CERC (Deviation Settlement Mechanism and Related Matters) Regulations, 2024 [Draft]

CERC notified draft regulations for Deviation Settlement Mechanism (DSM) and Related matters on 30th April 2024. The key highlights of this draft is mentioned below:

Objective: The revised draft regulations aim to bring regulatory control and protect the interests of stakeholders by ensuring compliance with the provisions under the Electricity Act, 2003 and Electricity Rules, 2005. The governing body have monitoring the grid events namely frequency excursions and frequency fluctuations. To ensure smooth and secure grid operation the new regulation have been designed accordingly.
New component added to definations of Contract rate: An alternative method of calculation have been introduced. It is weighted average ACP of the Day Ahead Market segments of all power exchanges for that time block.
To allow high cost power generate to participate in the DSM, High Price-Day Ahead Market (HP-DAM) have been included in Integrated-Day Ahead Market (I-DAM).
The states with RE installed capacity of more than 1000MW less than 5000 MW will be identified as ‘RE Rich State’ and state with more than 5000 MW as ‘RE Super Rich State’.
Normal rate will be calculated based on summation of fraction I-DAM, Real Time Market and Ancillary service charges.

APSERC (Framework for Resource Adequacy) Regulations, 2024 [Draft]

The Arunachal Pradesh Electricity Regulatory Commission notified draft “Framework for Resource Adequacy” on 28th February, 2024. The key highlights of the draft are mentioned below:

Objective: The sole objective of Resource Adequacy framework is the reliable fulfilment of the peak demand with the help of adequate supply of generation and demand response.

Important aspects of Regulation:

• Availability of adequate generation capacities to reliably serve demand under multiple scenarios.
• Optimal capacity mix based on minimization of overall system cost.
• Time horizon for the implementation of the framework should be 5-10 years.
• Energy storage, short-term sale/ purchase and other flexible resources under bilateral contracts will be incorporated into the resource adequacy framework.

• Loss of Load Probability: Measure of probability that a systems load will exceed the generation and firm power contracts available to meet that load in a year.
• Expected Energy Not Served: Expected amount of load (MWh) that may not be served for each year within the planning period.
• Net Energy Not Served: Total expected load shed due to supply shortages (MWh) as a percent (%) of the total system energy.
• Planning Reserve Margin: It is expressed as a certain percentage of peak load forecast of the system.

BEE (Detailed Procedure for Compliance Mechanism under the Indian Carbon Market), 2023 [Draft]

BEE notified draft “Detailed Procedure for Compliance Mechanism under the Indian Carbon Market” on 9th November, 2023. The key highlights of the draft are mentioned below :

Objective: The purpose and vision for the development of the Indian Carbon Market (ICM) is to accelerate decarbonization and meet Nationally Determined Contributions (NDCs) targets.

Legal framework:

• ICM was established under the Energy Conservation Act, of 2001, and the Environment (Protection) Act, of 1986.


• The Energy Conservation Act, 2001 empowers the Union Government to specify the Carbon Credit Trading Scheme (CCTS) and emission standards for obligated sectors. The Government of India notified CCTS on June 28, 2023.

Grid-India (Detailed Procedures for Security Constrained Unit Commitment (SCUC), Unit Shut Down (USD), and Security Constrained Economic Despatch (SCED) at Regional Level), 2023 [Draft]

Grid-India notified "Detailed Procedures for Security Constrained Unit Commitment (SCUC), Unit Shut Down (USD), and Security Constrained Economic Despatch (SCED) at Regional Level" on 07th September, 2023. The key highlights of the draft are mentioned below:


This document aims to clarify the roles and duties of different parties involved and provide a framework for operation of SCUC, USD and SCED. SCUC focuses on boosting reserves for grid security, while SCED strives to optimize electricity generation to achieve National Merit Order after gate-closure for RTM.

The procedure is applicable to thermal generating stations within regional entities whose tariff is determined u/s 62 of the EA, 2003 and also to the other regional thermal generating stations willing to participate in SCUC/ SCED. Thermal generating stations opting for SCUC are mandated to participate in SCED as well.

The procedure defines the roles of NLDC, RLDC and RPC w.r.t the SCUC, SCED, USD and the settlement/compensation mechanisms for the generators.

The list of generating stations along with their synchronization time and date, need to be operational in the next two days will be published two days in advance at 10:00 hrs. Also, the list of units required to operate on the following day under different conditions (hot, warm, and cold) will be published on the NLDC website daily at 15:00 hrs, including the date and time.

The beneficiaries can revise their schedule for the units scheduled below the turndown level by 14:30 hrs. of D- 1 and

CERC (Sharing of Inter-state Transmission Charges and Losses) (2nd Amendment) Regulations, 2023 [Draft]

CERC notified draft on “Sharing of Inter-state Transmission Charges and Losses” on 17th March, 2023. The key highlights of the draft are mentioned below:

Objective: To determine the Yearly Transmission Charges (YTC) in case of an inter-state Transmission system (ISTS) which has achieved deemed Date of Commercial Operation (CoD).

The YTC for the Inter-state transmission licensee which has achieved the deemed CoD shall be treated in the following manner:
1) 20% of YTC shall be paid to the inter-state transmission licensee for a period of 6 months from date of deemed CoD or till commencement of actual power flow, which is earlier.
2) 100% of YTC shall be paid to the inter-state transmission licensee from 7 month till commencement of actual power flow if actual power flow does not commence within a period of 6 months from deemed CoD.
3) The above mentioned YTC shall be disbursed from monthly transmission deviation charges under third bill. In case of shortfall, the balance charges shall be recovered from charges collected under T-GNA. In case of further shortfall, balance charges shall be paid from Deviation and Ancillary Service Pool account under DSM Regulations.
4) If ISTS of an inter-state transmission licensee (say A) achieves deemed CoD due to delay in commencement of power flow of in its ISTS because of other inter-state transmission licensee (say B), then B shall pay 20% YTC of its transmission system or 20% of YTC of the transmission system of A, whichever is lower till its delayed ISTS system achieves CoD.
5) If ISTS of an inter-state transmission licensee (say C) achieves deemed CoD due to delay in commencement of power flow of in its ISTS because of an inter-state transmission licensee (say D), then D shall pay 20% YTC of the transmission system of C, till its delayed inter-state transmission system achieves CoD.
6) The reimbursement of transmission deviati

MoP (Draft Proposal on Day Ahead Operation of Security Constrained Economic Despatch), 2023 [Draft]

Ministry of Power (MoP) notified a draft on Day-ahead (DA) Operation of Security Constrained Economic Despatch (SCED) on 24th January, 2023. The key highlights of the draft are mentioned below:

Objective: The main objective of DA-SCED is to expand the scope of SCED by involving more plants and run the SCED on a DA basis for providing a look-ahead schedule. The draft proposes to expand national-level merit order scheduling under SCED by including all inter-state generating station (ISGS), which can declare their compensation charge on a monthly basis.

Proposed procedure of DA-SCED:
1) ISGS participating in DA-SCED shall submit their declared capacity along with ramp rate and minimum turndown level for the next day (D) on D-1 by 06:00 hrs.
2) The entitlements and the share of beneficiaries shall be declared by respective RLDC on D-1 by 07:00 hrs.
3) The beneficiaries shall submit their requisitions/schedules from ISGS on D-1 by 08:00 hrs.
4) The injection and drawl schedules shall be prepared by respective RLDC, based on availability and schedules submitted by 09:30 hrs.
5) The first run of DA-SCED shall be carried out on D-1 at 09:45 hrs before the opening of the bidding window of DAM. Based on the results, the ISGS have a choice to participate in Day Ahead Market (DAM) as well as Real Time Market (RTM).
6) The second run of DA-SCED shall be carried at 17:30 hrs. This will help in re-assessing the SCED schedules for the next day (D) and the committed reserve capacity available through DAM-AS.
7) If available reserves are less then the required quantum then additional units would be deployed which shall be included in the third run of DA-SCED for 96-time blocks done by NLDC at 22:00 hrs.
8) The payments for the stations where incremental power is sc

CERC (Terms and Conditions for Dealing in Energy Saving Certificates) (First Amendment) Regulations, 2022 [Draft]

CERC notified the draft entitled Terms and Conditions for Dealing in Energy Saving Certificates (First Amendment) Regulations, 2022. The key highlights of the draft are mentioned below:

In these Regulations, the term 'Floor Price' has been introduced and is defined as the minimum price at which the Energy Savings Certificate shall be traded on the power exchanges.

The floor price is proposed to be fixed at ten percent of the price of 1 mtoe of energy consumed as notified by the Central Government from time to time.

Currently, the price of 1 mtoe is Rs. 18402/- as notified by the Ministry of Power (MoP) on 7th January, 2021.

CEA (Flexible Operation of Thermal Power Plants)

Central Electricity Authority on 7th July, 2022 notified the draft on Flexible Operation of Thermal Power Plants Regulations, 2022. The key highlights of the draft are mentioned below: These Regulations shall apply to all coal and lignite based Thermal Power Plants (TPPs) and Load Despatch Centres (LDCs).

Suitability of unit to operate for flexible operation:
a) Power plant unit throughout their service life shall be considered for flexible operation.
b) The start/stops and deep load following of corresponding unit shall be assessed.
c) The condition assessment of existing plant system and its upgradation if required.

All TPPs shall be capable of providing the required output as per the schedule for generation analized by appropriate LDCs.

The appropriate LDCs shall schedule all coal based TPPs up to the Minimum Power Level (MPL) of 55%, to support the operation of must run stations. The appropriate LDCs may schedule all coal based TPPs up to the MPL of 40%, subject to the required modifications for suitability of plant in flexile operations to support the operation of must run stations.

The minimum rate of loading or unloading for coal based TPPs shall be 3% per minute above the MPL. Provided that for supercritical and ultra-supercritical units, minimum rate of loading or unloading shall be 5% per minute above the MPL.

POSOCO (Detailed Procedure for Estimation of the Requirement of SRAS & TRAS at Regional Level), 2022 [Draft]

Methodology for assessment of the SRAS & TRAS reserves includes:-

a) 99 percentile of the Area Control Error (ACE) of the respective control area
b) Net demand forecast error
c) Variability in Net demand forecast error
d) Variability in Net demand
Amongst these, provisionally NLDC has considered the '99 Percentile of ACE of the respective control areas' method for the assessment of SRAS & TRAS reserves. NLDC is exploring other methodologies parallelly. Any improved methodology would be subsequently adopted subject to approval by CERC. Required quantum estimation of SRAS & TRAS has to be done by NLDC in coordination with the RLDCs and SLDCs as per the methods specified in the draft Guidelines. This data must be furnished by the SLDCs which must maintain reserves as estimated by NLDC.
Area Control Error (ACE) = (Ia-Is) – 10* Bf * (Fa-Fs) + Offset
Where, Ia & Is = Actual and scheduled net interchange in MW respectively (+ve value for export)
Bf = Frequency Bias Coef?cient in MW/0.1 Hz (negative value)
Fa & Fs = Actual and schedule system frequency respectively (default = 0)
Offset = Provision for compensating errors such as measurement error; default value zero

UERC (Deviation Settlement Mechanism and Related Matters) (First Amendment) Regulations, 2022

Amendment of Regulation 2 of the Principal Regulation (Definitions and Interpretation):

New Definition added after definition (d) of the Regulation 2 of the Principal Regulations:"(da) "Area Clearing Price (ACP)" means the price of a time block electricity contract established on the Power Exchanges after considering all valid purchase and sale bids in particular area(s) after-market splitting, i.e., dividing the market across constrained transmission corridor(s)."

IEX: Approval of Introduction of Additional Term Ahead Contracts and Green Term Ahead Contracts Beyond T+11 Days

Contract Proliferation and Loss of Liquidity:

The proposal to introduce numerous new contracts should be vetted against their impact on the liquidity and competition in the market for existing contracts. This can be avoided to some extent by ensuring that the long-term contracts are 'closed' before the shorter ones. For example, the marker clearing for the monthly contracts should precede the bidding window for the fortnightly contract and so on.
Issue with the Proposed Contracts in G-TAM (Clause No. 22): Introduction of multiple contracts for the GTAM may be delayed till this market segment attracts significant liquidity. Furthermore, due to their dependence on weather, it is difficult to forecast generation from renewables 1 month or even a week in advance.
Fortnightly Contracts (Clause No. 22(a)(iii)): The duration of the second fortnight under a Fortnightly Contracts should be flexible and relate to the number of days in a calendar month. For example, in February the length of the second Fortnightly Contracts may be either for 14 days or for 13 days, and, for a month with 31 days the length of the Fortnightly Contracts would be 16 days.
Any-day(s) Single-sided Contracts (Clause No. 22(a)(vi)): Any-day(s) single-sided Contracts are akin to the contracts currently executed through the DEEP Portal but with a wider applicability for all kinds of buyers and sellers. In any case, single-sided contracts should be avoided as it will not have competition on the demand side.

Tamil Nadu Electricity Supply Code on Stipulating Harmonic Limits, Methodology of Measurements, Meter Standards, Penalties etc., to ensure Quality of Supply to Consumers [Draft Amendment]

Scope of Applicability of the Regulation (Regulation 1 (c)):

Applicability of the draft regulation seems to be ambiguous as "Measurement of current distortion/harmonic currents shall be made at the PCC of the installation of bulk consumers at 33kV and above and consumers, prosumers, charging stations below 33kV", also refers to consumers connected below 33kV. This may seem to suggest it's applicability to all the consumers of DISCOMs. Also, the PCC needs to be de?ned in the draft Regulation.
Violation Limit for Individual and Total Harmonics: The Commission may like to seek appropriate technical advice (say, after 3 year of implementation of these Regulations) from a reputed research institution/organisation working on the engineering/technical aspects of power system to identify the scale of problem of harmonic within the system and then consider appropriate adjustment in the multiplier (currently 1.5) for 99th/95th percentile limits.

CERC (Ancillary Service) Regulations, 2021 (Draft)

Design of Market for Ancillary Services:

Ancillary services have a very important role to play in secure operation of a power system. Increasing share of variable renewable energy sources, demand further attention of system operator. Reserves Regulation Ancillary Services (RRAS) has played a key role in bringing stability in system frequency. However, current design of ancillary services does not incentivise fast response ancillary services, which is critical in operation of ancillary services with high VRE share. Furthermore, RRAS, in its current form, is also restrictive in terms of eligibility for participation.
Definition of Demand Response (Regulation 3 (1)): The definition of demand response refers to the same being identified by the NA as per the system requirement. This might be construed to mean that the NA would identify demand response as one of the 'Supplier for ancillary services', whereas such specificity is not attached to other suppliers of ancillary services. Regulation should provide clarity with respect to the same. Further, variation in drawal by the control area should be attributable to demand response only if this is achieved through back-to-back volunteer demand reduction by the consumers, rather than load management/load shedding by the distribution company.

POSOCO-NLDC Detailed Guidelines on Ramping Assessment

'Gate closure' for declaring ramping capability should be specified in line with that used for scheduling.

Td /Tm? 0.85 - Clause 4 (4): A threshold limit of 0.85 assumes that 15% of the time blocks across the year d m witness exigencies. This would be a significant over-estimation for most of the generating stations. Furthermore, the blocks with DC = 0 or schedule < technical minimum are already excluded from Tm. Since various exigencies can be identified and recorded, such time blocks can then be excluded while calculating Td /Tm. The guidelines seem to suggest that number of time blocks (Td) considered already exclude exigencies. If so,the threshold limit of 0.85 would not at all be justified. It is also important to note that the generating stations are allowed full recovery of fixed charges at 85% of availability.

MoP's draft proposal on Relinquishment of PPA beyond Tenure

Benefits of PPA Relinquishment:

Relinquishment of old PPAs would provide a relief to those states/DISCOMs which have excess PPAs by reduction in the fixed charges as well as overall reduction in the burden of transmission charges. The states/DISCOMs surrendering power would still have an option to buy the same 'surrendered capacity' through the market, likely at lower price than existing PPA. This will motivate the DISCOMs to be proactive in their power procurement management. This would also be beneficial for the development of the power market in the country as it will infuse additional liquidity in the market.
Plants with recent CapEx: It should be clarified if PPA relinquishment is possible in case of such plants wherein additional capitalization was undertaken in recent past (prior to completion of 25 - year tenure of PPA), and which is yet to be depreciated to the allowable limit, and wherein the associated debt repayment (if any) has only partially been undertaken.

CERC (Power Market) - Regulations, 2020

" Market Coupling " (2 (af) & 37):

The process of market coupling can bring economic efficiency gains for the market as a whole particularly for the market products with low liquidity. The country has adopted 'market coupling' through the SCED mechanism thereby bringing significant cost efficiencies in the sector. Internationally, such market coupling has been adopted for integrating a number of hitherto uncoupled markets.European electricity market provides a practical example of such a coupling that links a number of control/market areas thus reducing price differentials. In 2010, European countries adopted Price Coupling of Regions (PCR) that evolved into Multi Regional Coupling (MRC) that now includes 19 European countries.
' Coupling Across Market Areas ' vs ' Market Platform Coupling ': SCED is an example of coupling across market areas. This has improved/optimized cost of power procurement by utilities leading to cost savings. A Power Exchange (PX) itself presents an example of coupling across 'market areas'. This is violated only in the case of market splitting. So far, we did not have a provision for coupling across market platforms. Let us also consider some of the analogous contexts in capital and commodity markets.The two leading stock exchanges of the country, the BSE and the NSE, which have continuous market trading remain decoupled as significant liquidity and competition has thinned possibility of arbitrage across these markets. Similarly, multiple commodity exchanges/market continue to flourish, some in the regional, and other in the national context. In the context of PXs, the principles of 'for delivery' should negate the opportunity for arbitrage even if there are differences in prices discovered across PXs for the same time block and market area. The difference in discovered prices across

Revised Procedure for Pilot on SCED for Generating Stations PAN India

In the light of participation of intra-state generators in the SCED, the intra-state grid code needs to be appropriately amended to account for SCED related re-scheduling and processes thereof.
In the case of merchant generators participating in SCED, the variable charges should be revised as per LTA/MTOAentered into and its supporting information should be shared with POSOCO.
In the case of central sector generators with unallocated capacity share, benefit sharing for such capacity should not be undertaken as 'untied'capacity for such durations.
In the absence of up gradation and seamless integration of SLDC software, the respective SLDC may exposed to a counter party risk in case of a communication failure. It highlights the need of adequate capacity building of SLDCs, and enhancing feedback protocols to identify and address such communication failures.

Allocation of Transmission Capacity

The framework for allocating transition corridor for RTM proposes to allocate transmission capacity across the Power Exchanges based on their share of volume in DAM. Clarification with respect to its applicability on a block-wise basis needs to be provided.

A mismatch between the allocated transmission capacity (as per the share of DAM) and potential clearing volume in RTM may lead to a situation wherein transmission resources allocated to one of the power exchanges having lower RTM volume vis-a-vis DAM may remain unutilised while the other PX may face a shortage of allocated transmission capacity. A similar problem would be encountered on account of 'minimum 10%' allocation of transmission capacity, even if share in DAM (or potential volume in RTM) was less than that. Such sub-optimal allocation of transmission resources would also lead to inefficient outcome of RTM in terms of cleared volume and prices.

Further, transmission charges for the allocated but unused transmission capacity would be borne by the users who finally use the transmission capacity. POSOCO should evaluate the impact of the allocation scheme and identify the pattern of underutilisation of allocated transmission capacity and seek suggestions to address the same.

The theoretical best solution would be to have common market clearing across the power exchanges, thereby achieving the most efficient market outcome. However, alternate mechanism should aim to mimic that outcome as far as possible.

Proposed Framework for Real Time Market (RTM) for Electricity

Alternate Auction Design - Since fixed cost for all the ISGS generators is borne by the beneficiaries, an alternate auction design, wherein their URS capacity is mandated to bid at their VC (plus 7 paise margin), can be considered. Merchant capacity can bid as per their economic value. Discovery of market price would thus become more competitive, and would help recover loss of consumer surplus (see figure below), thus benefitting the DISCOMs and the final consumers.
Active participation of generators and DISCOMs is crucial to the vibrancy of RTM. The current incentive structure across market segments especially the URS and the RRAS, which provides for recovery of associated fixed charges, may need to be finetuned. Initial experience with RTM may further help assess the need and direction for the same.

Proposed Framework for Real Time Market (RTM) for Electricity

Because of uncertainty related to short-term load forecasting, a liquid RTM would allow DISCOMs to reduce grid imbalances. Further, this will also assist greater RE integration across states.
Enhanced liquidity for Real Time Market (RTM) would also provide better value to electricity available across different hours of day. A two-hour ahead forecasting would provide a much reliable RE generation forecast specifically for RE sources like wind and solar.
RTM price signals should be used by the DISCOMs for designing more effective TOD/TOU tariff.
Although recent regulatory developments are leading to more efficient and competitive price discovery, the regulatory framework does not provide for appropriate signals for investment in capacity addition. A long-term objective should be to introduce a capacity market with active participation of the distribution utilities.

CERC - Deviation Settlement Mechanism and Related Matters (Fifth Amendment), Regulations, 2019

As per clause 4.5 (a) and (b), to meet sign change norm, regional entities (buyer or seller) deviating beyond ±20 MW with reference to schedule need to pay additional charges. This range may be suitable for smaller states. However, for larger states this range may be expressed in terms of percentage of schedule power.
As per provision of clause 4.5 (a) and (b), forced outage of a generating station participating in collective transactions on Power Exchanges are exempted from adherence to sign change norm. Such exemption due to forced outage may be applicable to all generating stations.
As per CERC's DSM 3 Amendment Regulation 2016, there are different methodologies for compilation of deviation charge. Post 3 Amendment to the Regulation in 2016, deviation charges for renewable rich states (states with installed solar and wind capacity 1000 MW) and the rest are differentiated. States like Gujarat, Karnataka, AP, MP, Punjab, Rajasthan, Tamil Nadu, Telangana and UP have reached 1000 MW RE generation capacity and few other states are close to reach this limit. As the number of states qualifying as renewable rich states rises, the asymmetric application of charges may need to be relooked in the future.

CERC - Pilot on SCED of Inter-State Generating Stations PAN India

Savings on account of SCED implementation, for which methodology is yet to be specified by CERC, should only be apportioned to the respective beneficiaries. Generators, who are otherwise compensated for all the associated cost, should not be a party to such savings.
The variable cost quoted by the ISGS for RRAS is vetted by neither CERC nor POSOCO. Moreover, it is not specified if this variable cost should be based on the previous month's billing or the current month's expected billing, or on the basis of the cost of recent delivery of fuel (in case of coal-based thermal station).
The asymmetry of variable cost used by state utilities and that quoted by ISGS plants (and used for SCED) would lead to over-/under-estimation of benefits.
Procedure for Pilot on SCED for ISGS PAN India
The SCED being implemented is based on variable cost at the generator bus bar, where states consider the landed cost of such power, including transmission charges and transmission losses, while determining the MoD. Hence, the results provided by SCED may be suboptimal for a state sometimes.

MBED of Electricity: Re-Designing of DAM in India - A CERC Discussion Paper.

Expected savings from optimisation over a larger portfolio of procurement contracts need to be weighed against costs associated with the implementation of MBED.
Relevant sections of Electricity Act, 2003 may need to be amended to facilitate the creation of MBED.
The proposed price risk hedging mechanism in BCS is asymmetric - allowing DISCOMs to hedge risk when MCP is greater than the price in the PPA(s), while exposing GENCOs to financial risks if MCP is less than PPA(s) price.
Some generating units may need frequent shut downs, especially in the absence of incentives to generate up to their technical minimum limit, when the system forces low demand or high renewable penetration, thereby affecting the overall market outcome.

CERC - Re-designing of Real Time Electricity Market in India

The existing DSM mechanism and AS (RRAS) are frequency-dependent imbalance handling tools, not to be used as markets. The design of RTM as a balancing market must ensure participation and reduce dependence on AS (RRAS) and DSM for real time energy needs.
A time gap of 10 minutes is required between gate closure and opening of bid (auction) for RTM.
Distribution utilities should be allowed to provide demand side 'up regulation' and 'down regulation' bids to enhance the overall market efficiency.
DSM price vector, currently linked with prices in DSM, could be linked to the prices discovered in RTM, at a later stage, for reflecting the true cost of deviation.