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)."

New Definition added after definition (i) of the Regulation 2 of the Principal Regulations: i. "(ia) "Daily Base DSM Charge" means the sum of charges for deviations for all time blocks in a day payable or receivable as the case may be, excluding the additional charges under Regulation 8."
ii. "(ib) "Day Ahead Market (DAM)" means a market where physical delivery of electricity occur on the next day (T+1) of the date of transaction (T) and is governed by the Central Electricity Regulatory Commission (Power Market) Regulation, 2010 (as amended from time to time), the Rules and Bye-Laws of the Power Exchanges as approved by the Central Commission."

Amendment of Regulation 7 of the Principal Regulation (Limits on Deviation Volume): Frequency range has been changed from "49.70-50.10" Hz to "49.85-50.05" Hz.

CERC (Connectivity and General Network Access to the Inter-state Transmission System) Regulations, 2021 [Draft]

CERC notified a draft on "Connectivity and General Network Access to the Inter-state Transmission System Regulations, 2021" on 16th December, 2021. The key highlights of the draft are given below:Objective: These Regulations aim to facilitate non-discriminatory open access to licensees, generating companies and consumers for the use of Inter-state transmission system (ISTS) through General Network Access and to consolidate the Regulations on the subject.

Connectivity: Eligibility for Connectivity to ISTS Following entities are eligible to apply for grant of Connectivity or for enhancement of the quantum of Connectivity:
(a) Generating station(s), including REGS(s), with or without ESS, Standalone ESS with an individual/ aggregate installed capacity of 50 MW and above through a Lead Generator or a Lead ESS;
(b) Captive generating plant with capacity for injection to ISTS of 50 MW and above;
(c) Renewable Power Park Developer;
(d) REGS or standalone ESS having an installed capacity of 5 MW and more, and applying for grant of Connectivity to ISTS through the electrical system of a generating station already having connectivity to ISTS.
An Applicant may apply for grant of Connectivity at
(i) A terminal bay of an ISTS sub-station already allocated to another Connectivity grantee or
(ii) Switchyard of a generating station having Connectivity to ISTS.
Two or more Applicants may apply for grant of Connectivity at a common terminal bay with an agreement duly signedby such Applicants for sharing the dedicated transmission lines and the terminal bay(s).

Transfer of Connectivity: A Connectivity grantee shall not, transfer, assign or pledge its Connectivity and the associated rights and obligations, either in full or in parts, to any person. Provided that the Connectivity granted to a parent company may be utilised by its subsidiary and the Connectivity granted to a subsidiary may be utilised by its parent company.

General Network Access (GNA): Eligibility for GNA The entities listed below are eligible as Applicants to apply for grant of GNA or for enhancement of the quantum of GNA:
a) State Transmission Utility on behalf of distribution licensees connected to Intra-state transmission system and other Intra-state entities;
b) A buying entity connected to Intra-state transmission system;
c) A distribution licensee or a Bulk consumer, seeking to connect to ISTS, directly, with a load of 50 MW and above;
d) Trading licensees engaged in cross border trade of electricity in terms of the Cross Border Regulations;
e) Transmission licensee connected to ISTS for drawal of auxiliary power.

Deemed Grant of GNA: GNA for (i) a State including Intra-state entity(ies) and (ii) other drawee entities, shall be the average of 'A' for the financial years 2018-19, 2019-20 and 2020-21, where, 'A' = {0.5 X maximum ISTS drawal in a time block during the year} + {0.5 X [average of (maximum ISTS drawal in a time block in a day) during the year]} Read more...

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. For Example: In Reverse Auction, Buyer A will buy 50 MW for one day and Buyer B will buy 100 MW for the same day. In such case, it should be clarified whether the bids would be cleared on pro-rata basis. Read more...

IEX: For Amendments In Business Rules For Introduction Of Gross Bidding On IEX Platform

MBED as Gross Bidding:The overall design & philosophy of the proposed 'Gross Bidding' is similar to that proposed under the Market Based Economic Dispatch (MBED) framework. While theoretical merits of the proposal are understood, there are numerous implications arising out of the existing operational constraints as well as regulatory framework for determination of generation tariff for inter as well as intra-state generation assets. Some of these are discussed herein. Given that the proposed bidding framework has significant implications for the overall market design and its outcome, it is important that this should be discussed thoroughly at a broader level and be implemented with a clear market direction with regulatory oversight. While relevance and role of the concepts are relatively clear, the preparedness and capacity building needs of the participating DISCOMs need to be addressed.

SCED vs Gross Bidding: The prevailing framework for Security Constrained Economic Despatch (SCED) allows for optimisation of 'marginal' power procurement. From a DISCOM's perspective, gross bidding would be favorable than SCED as it provides a larger canvass for optimisation than currently available (being limited largely to the inter-state generators). In financial terms also, DISCOM would gain as it would be able to receive full benefit (MCP-PPA) due to sale of part or full capacity of its marginal PPA to another market platform through Gross Bidding.

Treatment of Incentives/ Penalty/ Compensation under the Prevailing Regulatory Framework: The existing regulatory framework particularly for the inter-state generating stations, under the applicable CERC's (Terms and Conditions of Tariff) Regulation, provides for the following specific charges/ incentive/ penalty. Compensation part load operation - Incentive structure for higher availability during the peak/ off-peak hours - Incentive/ penalty for demonstrating/ failure to demonstrate ramping capability of the generating plants. These charges would continue to be borne by the respective beneficiary. In the emerging market environment, it is advisable to do away with such digressions that vitiate the market price discovery.

Need to Run MoD before participation in Gross Bidding: The optimal scheduling and dispatch practices ensure that the 'required' plants are operated at technical minimum and also operated within the ramping limits. However, the 'Gross Bidding', or to that matter any other bidding on the PX, ignores such constraints. To avoid such a situation, the participating DISCOM can undertake prior optimisation exercise on a stand-alone basis, and then use the results to decide its 'bidding strategy' under gross bidding. This approach would be necessary till the development of a wide-spectrum and efficient market for ancillary services.

Price limit on DISCOMs Price Bid: In case a DISCOMs demand bid exceeds its supply bids, the DISCOM should specify price bids for the excess quantum which should not be 'expected' and bid at the maximum bid of Rs.20/kWh, so as to avoid the high price discovery in the market. In fact, if the demand and supply quantum bids are equal, the maximum buy bid should be limited to the highest energy charge of the PPAS that the DISCOM would bid into the Gross Bidding. It is important to note that the DISCOMs, and hence the consumers need to be safeguarded from price volatility in the market. Careful market considerations and vigilant market monitoring are required to ensure the same. Risks associated with such participation need to be identified by the DISCOMs and be addressed both in terms of their power procurement planning as well as bidding behavior across market segments. Read more...

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

Standards for Harmonic Filters: The filters to mitigate the harmonics to be deployed by consumers should be in accordance with the applicable IEEE or BIS Standards. The Regulation may identify the same.

Calculation of Penalty (Regulation 1 (h)): The statement "TDD excess % over and above the limit" may be rewritten as 'TDD in excess of the percentage points over and above the limit' to provide more clarity.

After the installation of harmonic lters, the licensee should conduct a test within 6 months of each such installation. In case of the harmonics going beyond the prescribed limit, adequate filters needs to be installed within the next 6 months, otherwise penalty should be applied.
In case of failure of two subsequent tests after each installation of the harmonicfilters, the penalty should be applicable for each of the preceding months, since the rst installation of the harmonic filter. In the absence of such a provision, the consumer may perpetually extend installation of appropriate harmonic lter and also avoid the payment of penalty. Read more...

CERC (Deviation Settlement Mechanism and Related Matters) Regulation, 2021

ATimeliness and Need for Amending Deviation Settlement Mechanism (DSM) Regulation:Deviation Settlement Mechanism (DSM) (and the erstwhile Unscheduled Interchange (UI)) were introduced amidst uncertainty associated with electricity demand and supply. Rising share of Renewable Energy (RE) has further exacerbated overall uncertainty to ensure demand supply balance in the power system. Evolving market structure, especially with the implementation of the Real Time Market (RTM), and proposed market for Ancillary Services (AS) provide an opportunity for the DSM price signals to be more closely associated with value of deviations close to the real time. However, a number of issues identied herein need to be addressed to ensure that the implemented scheme is able to efciently address the issues in the evolving scenario.

Definition of RE Rich State: A RE rich state is dened as a state with 1000 MW or above installed capacity of Variable Renewable Energy (VRE) (i.e. Solar and Wind) within the control area of the state. The variability and uncertainty associated with the schedule of a state depends on the 'contracts that it handles for consumption within the state. The RE rich state should thus be dened with reference to the contracted capacity of VRE by all entities connected to the 'control area of the state' (i.e. including long-term open access for VRE by consumers).

Additional Deviation Limit and DSM Applicability for RE amidst Growing RE Share: Given the growing VRE capacity across states, more states would soon be added to the list of RE-rich state. In a few years, most of the larger states may qualify as RE rich state. Relevance of additional deviation limit would then no longer exist, and would need to be re-evaluated.

Additional Limit for RE Rich State: RE rich states, dened as states with 1000 MW or above installed capacity for Solar and Wind energy, are allowed 250 MW deviation limit against 150 MW limit for other states. The additional deviation limit should be linked to the 'impact' that higher capacity of variable RE (wind & solar) brings to RE rich states as compared to other states. Some states with, say 900 MW VRE capacity, may be subjected to higher uncertainty due to the resource prole and, mix of solar and wind energy.
Further, higher deviation limit would continue to dissuade investment in demand side management and economical energy storage (pumped hydro, BESS (when economical) etc). The former needs much more attention due to its lower cost as compared to other options.

Need to Finalise Ancillary Services Regulation: The draft Regulation proposes deviation charges to be linked to, among others, to the discovered price for ancillary service products. the ancillary services' Regulation, which is yet to be finalised, would have implications for the design and implementation of the amended DSM. It is suggested to finalise the AS Regulation to bring a clarity to its role and efciency. This would also address regulatory uncertainty by providing adequate information to the stakeholders to evaluate its impact on DSM and hence the deviation charges that may need to pay. Read more...

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.

Define Demand Response Aggregator: A 'demand response aggregator' should also be defined, and its role be specified in the definition of demand response.

Embargo on taking back the surrendered capacity share: Astate surrendering its share in CGS may not be excluded to take back the surrendered capacity at a later date. The condition Clause 3 (7) (a) (3) should thus include the surrendering state within definition of 'single buyer'.

Definition of Energy Storage (Regulation 3 (1n)): The definition of Energy Storage may be modified as “Energy Storage in relation to the electricity system, means a facility where electrical energy is converted into any other form of energy which can be stored, and subsequently reconverted into electrical energy which is injected back tothe grid”.
The text in bold should be added to bring clarity to the definition. Insertion of 'other' would ensure presence of anintermediate technology to convert conversion electricity to the other form. In the absence of stored energy beinginjected back to the grid (after accounting for conversion losses), storage would only behave as a load.

Definition and Computation of URS (Regulation 3 (1ae)): URS means the surplus capacity of a generating plant that has not been requisitioned by the beneficiaries, and is available for despatch. It should be computed as the difference between the declared capacity of the generating station and its total schedule by the respective beneficiaries. This should, thus, be calculated 'prior to scheduling and despatch of the respective ancillary services'. Read more...

MoP Discussion Paper on Market Based Economic Dispatch (MBED)

Relevance of MBED:Experience with short-term power market development provides a test case for the maturity of the sector to adopt such a change, and the preparedness of most of the stakeholders to participate in the same.However, the experience varies across states in terms of the avenues for optimisation and the ability of the available practices and tools to do so.
It is also important to mention that the current market design provides for voluntary participation. MBED is a departure from the same as it entails broader participation across the distribution utilities.
As per EAL opinion, competition for fixed charges should be through capacity market while competition on variable charges through MBED.

SCED vs MBED: SCED optimises power procurement fro m eligible ISGSs. MBED, if implemented only for the eligible NTPC generators (as proposed), the gains (in terms of optimised cost of power procurement) would be limited and may be of similar order as in the case of SCED. Without participation of intra-state generators, true gains of MBED would not be realised.

Gate Closure and Right to Recall: MBED, implemented on a Day-Ahead basis would require the utilities to forego 'right to recall'. Post submission of the bids to MBED (i.e., at gate closure), the generators as well as the DISCOMs commit themselves to sell/buy the cleared quantity. This loss of flexibility (associated with 'right to recall') to the distribution utilities is of value on account of the uncertainty associated with demand as well as RE generation forecast.
Under MBED, DISCOMs can rebalance their portfolio in the Real Time Market (RTM). Depending on the market conditions and the need to buy/sell, the DISCOMs would have to bear the additional burden due to rebalancing oftheir portfolio.

Long-term Impact on Investment and Need for Capacity Market: MBED is designed as an energy market, wherein existing beneficiaries of the PPAs continue to pay the associated capacity charges. The market participants, procuring energy through the MBED platform, only bear the market clearing price associated with such capacities. This does not provide an incentive for signing long-term PPAs tied up to payment of such fixed (capacity) charges.
To ensure that adequate investment is undertaken to maintain resource adequacy in the system, MBED should be supplemented with a capacity market. Design of such a capacity market would need to take into account a reasonable estimate of resource adequacy that needs to be tied up with the existing consumer base of the load serving entities, as well as other entities (for e.g., large consumers) who would be eligible to directly participate in the MBED in the near future.

Generator's Bid and Variable charges and flexibility thereof: The generators, whose tariff is regulated u/s 62 of the Electricity Act 2003 should bid at their variable charge.Given the adopted price discovery mechanism, i.e. the uniform market price, the marginal generator would dictate the market clearing price in MBED to ensure efficient price discovery in MBED, wherein the generators should be close to their marginal cost, the generators with regulated tariff should therefore bid at their variable charge or below. This will ensure that a higher bid by such marginal plants do not dictate the market clearing price, and hence increase the overall burden for distribution utilities, and hence the end consumers. Read more...

POSOCO-NLDC Detailed Guidelines on Ramping Assessment

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

Table 1: Various relaxations for ramping assessment of ISGS

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.

Calculation of E and F for ARRt ≥ 50% of SRRt - Clause 4(5): While calculating E, a SRR of 0.5% in a preceding time block assumes that the concerned generating station would experience technical challenges in bolstering up its ramping, for example, from 0.5% (t-1) to 1% (t) in the subsequent time block. It is likely that generating stations may often be subjected to such incrementally higher ramp rate. While, an increase in SRR from 0.51% to 1.0% may be justified, whereas 0.5% to 0.9% may not be.

The 50% relaxation applicable for subsequent time block may often result in ARR < 0.5. For example, it would be ironic that an ARR of 0.4% (against SRR of 0.8%) would be acceptable for a subsequent time block. While preceding time block may have already witnessed SRR or ARR > 0.5%. We suggest that this relaxation should be lowered, and the resultant qualifying ARR ( to be counted in E) should at least be 0.5%.

This relaxation should only be applicable in case of SRR ≤ 0.5% and ARR ≤ 0.5% (i.e. not if ARR > 0.5%).

Ramp rate tolerance of 10% - Clause 4 (6): The perceived randomness (of physical systems) inherently assumes a skewed distribution, wherein a 10% shortfall in ARR is condoned but 10% over-achievement of ARR is incentivized. From the perspective of beneficiaries, a similar tolerance should then also be provided on over achievement of ARR i.e., an ARR = 1.1% should be counted as ARR = 1%, thus saving payment of incentive.

D ≥ 60M for E/D and D ≥ 90M for F/D - Clause 4 (10): The provision for additional RoE or reduction in RoE is applicable across the whole year, whereas higher (scheduled) ramping capability needs to be demonstrated only 2-3 blocks/day, and which may be achievable in an economical manner.

Cumulative impact of relaxations: The relaxation in key parameters (Tm , Td /Tm , E & F, E/D & F/D, ramp rate tolerance) towards assessment of demonstrated ramping results in cumulative relaxation of 23.5% to 66.25% while calculating eligibility for additional (penal) RoE.

The overall framework merits further discussions to address some of the identified issues to ensuring that the guidelines are fair and equitable, while also providing sufficient incentive (penalty) for over (under) performance of ramping capability. Analysis of system/generator-wise data should provide input for same.

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.

Modification of Terms and Conditions of PPAs (Clause 3 (5) & 7 (a) (3)): The draft proposal should provide for a state/DISCOM relinquishing its share in a central generating station to sign a new PPAwith CGS under modified terms and conditions which can be attractive for the state/DISCOM.

Embargo on taking back the surrendered capacity share: Astate surrendering its share in CGS may not be excluded to take back the surrendered capacity at a later date. The condition Clause 3 (7) (a) (3) should thus include the surrendering state within definition of 'single buyer'.

Competitive Bidding for Surrendered Power (Clause 3 (7) (a)): The relinquished capacity of central generating station should preferably be offered through a process of reverse bidding, with regulated tariffs as a ceiling. Most of the power surrendered by the states/DISCOMs would generally have higher variable and fixed charges burden. Therefore, such expensive power plant, once relinquished by states can only survive in the market when the generators are able to bid lower than the existing variable charges, and thus would have to endeavour to decrease their variable cost.

Discount on Regulated Tariff (Clause 3 (7) (a) (3)): Since the surrendered power, being expensive and surplus, does not have sufficient offtake through the URS route, offering the same capacity at regulated tariff may not be attractive enough for the potential buyers. The generator, whose capacity has been surrendered by a beneficiary, should have the option of offering the same to the willing buyers at a discount to the regulated tariffs.

Time/Season Based Power Relinquishment: Some of the beneficiary DISCOMs may have excess power only during off-peak hours, and may like to retain the capacity during peak hours. Similarly, there may be seasonal surplus with the beneficiaries. The flexibility to relinquish the PPA only for the identified season, time blocks of the day, and weekdays/weekends would allow better optimization of power procurement portfolio by the DISCOMs. Such an option for surrendering the PPA capacity will also reduce annual fixed cost burden for the beneficiary DISCOMs, and would incentivise them to retain the modified PPA. An appropriate regulatory mechanism would be required to determine the regulated fixed charges in such cases.

End of Life Plants and FGD Investment: Power plants nearing the end of life and needing significant FGD investment, would witness significant increase in regulated tariff. Such plants, even though which may not have completed 25 years of PPA, may also be eligible for relinquishment of capacity under the draft proposal.

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 the PXs arises not only on account of differences in bids, market participation and liquidity, but also the price discovery algorithms adopted by the PXs.

Three Propositions for Market Coupling: Considering that it is going to be a significant step with distributional impact across the market platforms and may also influence future investment, the following three steps may be adopted in the interim.
(i) Adopt market coupling for the market products with low liquidity. For example, the TAM, which need this more than the more liquid market products.
(ii) Provide for a uniform algorithm across PXs, as adopted in the European context.
(iii) Increase the depth of the market as it currently covers around 4.3% of the total electricity generated in the country (2018-19) and had only marginally inched up this year. This would increase liquidity and competition across PXs. Higher liquidity and introduction of MBED may obviate the need for the market coupling in future.

Phased Implementation - Begin with Low Liquidity Products: Given the significantly skewed market volume across the two power exchanges, there would be distributional impact of the market participants on the PXs. It would be useful to present a summary of the overall efficiency gains and the distributional impact, if any. This may help in evaluating overall impact for the sector. One would also expect likely redistribution of cleared market volume across the PXs. Given that such market coupling would significantly erode the value of one of the leading PX, which has been built its clientele due to its business practices, such an assessment would be desirable for long-term market development in the country. Further, the market coupling would be significantly beneficial for those market products which have considerable low liquidity. For high liquidity market segments, one would expect higher levels of market efficiency

Market Coupling and Payment Risk: How would payment risk associated with the market clearing and payment would be managed across the multiple PXs? Would that mean 'coupling' of the same as well?

Objectives of Power Exchange (8): "(1) To design electricity contract.....(2) To facilitate extensive,quick....dissemination." should be replaced with "(1) To standardize electricity contracts....(2) To facilitate fair, transparent , quick, efficient, and extensive dissemination of the market outcome " .

Prevention of Cartelization in Market Oversight (49): Cartelization may be either explicit or otherwise demonstrated in the action of the participant. The provisions for market oversight should include both cases.

Capacity Market and Ancillary Services (4): The regulations should provide greater detailing of market design and, price discovery for ancillary services and capacity market. It is not currently included in the draft. Provisions for the introduction of such market, design of contracts and the role of the PXs over such contracts is ambiguous.

Design of Market for Ancillary Services: Given that ancillary services (the RRAS) is currently being managed and needs to be managed by a system operator, the present design has limited participation and does not foresee participation by broader set of system constituents including provider of storage services as well as aggregators for demand response schemes.Considering that SCED has been expanded to include intra-state entities, a similar approach can be adopted for RRAS. Further, improvement in the market design may be brought about by introducing single side bid-based price discovery allowing participation of generators on a competitive basis. This would also provide for participation of merchant generators as well as aggregators for demand response.

Co-optimization for Ancillary Services: A research undertaken at Energy Analytics Lab (EAL) demonstrated benefits of co-optimization of energy and RRAS market in the Indian context. Adoption of a similar approach can be considered to enhance overall cost efficiency.

Roadmap for Power Market Derivatives: As the power market matures, there may be a case for introducing derivatives for legitimate market participants with direct exposure to the buy/sell positions.The Commission may float a discussion paper for further deliberating a roadmap for introduction of derivatives for electricity contracts in the country.

Prevention of Circular Trading (2 (k)): Legitimate needs for taking buy to sell or sell to buy position across different market segments may arise due to the availability of more reliable information about generation/demand near to the time of delivery. For example, a decrease/increase in demand or generation from RES may necessitate the need to offload a buy/sell contract cleared in the DAM, in the RTM later. However, circular trading that aims to enhance the market volume with no intention of taking the delivery should be checked. The regulation should further elaborate on circular trading (primarily meant for squaring off the positions) and differentiate with the rebalancing of the portfolio (for delivery services).

Insider (2 (z)): An insider should also include a person who has acquired unpublished price sensitive information through unfair/unethical means in addition to those through criminal activity.

Unpublished Price Sensitive Information (2 (bf)): This should also include information relating to contracts to be transacted or those that were supposed to be transacted on a PX. The price sensitive information should also include quantum along with price of the contract.

Price Discovery (5.1 (a)): " Price Discovery shall be done by Power Exchanges or by...." should be replaced by " Price Discovery shall be done by Power Exchanges, or by Market Coupling Operator, as and when notified by the Commission.

Scheduling and Delivery of Term-Ahead Market (3 (b) (iii))): Physical delivery mechanism is considered only in the case of Term Ahead Contracts. - " Term Ahead Contracts shall be settled only by physical delivery of electricity without netting and shall be binding on the participants executing the transactions "

Contracts Transacted on the OTC Market (7.1): The regulations identify the role of the SERCs to regulate the OTC market, seemingly for intra-state transactions. There is discrepancy regarding OTC market as approved by the SERCs, they would not be able to carry out inter-state transactions.

Delivery Procedure for OTC Market (7.2 (i)): The delivery procedure of Open Access Regulations should be determined by the Appropriate Commission. Moreover, the preference order for 'delivery' is not clearly stated.

Bye-laws, Rules and Business Rules of Power Exchange (19): "Trading margin for a Trader Member and service charge for a Facilitator Member" is defined as a part of bye-laws, rules and business rules in accordance to which the PX should function. But it is not clear, how a PX will monitor the buying and selling price for a trader/facilitator member to ensure that appropriate trading margin/service charges are being levied.

Management of Power Exchange (20): The qualification of one of the three full- time professionals is mentioned as "Degree in Computer Science/Computer Application/Information Technology with...",which should be made generic as nomenclature for such degree differs across institutions.

Objectives of the OTC Platform (42.2): This should include "To ensure transparency and an efficient participation and price discovery, the information regarding availability of various contracts and the contracts executed on OTC platform should be made available in the public domain".

Trading Margin and Service Charge (24): " Provided that the service charge shall not include any charges...." should be replaced by "Provided that the trading margin and service charge shall not include any charges....".

Market Surveillance by Power Exchange (32.5): The quarterly surveillance report submitted by Market Surveillance Committee should be made publicly available along with market monitoring report of CERC.
In addition to the market surveillance undertaken at the level of the PXs, an overall market surveillance would be required for effective market coupling. This will also help to monitor the circular trading involving more than one PX.

Designation of Market Coupling Operator (38): The criterion for selection of Market Coupling Operator is not included in the draft regulation. Certain key aspects for the same should be identified.

Procedure for Market Oversight (50.2 (b)): "Involvement of Market Participants in any of the...." should be written as "Involvement of Market Participant(s) in any of the...."

Regional Participation on the Indian Power Exchanges: The Indian PXs may provide for trading of cross-border as well as country-specific contracts in future. An enabling provision, taking into account developments under regional cooperation treaties, may be included.

Market Manipulation: Definition of "Market Manipulation" should include the case of 'secures or attempts to secure, by any member of the PX or client, relatively lower buy price while curtailing supply to other beneficiaries entitled to receive the same power'. It should include disseminating any information not only through the media but by any means.

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.

Definition of Net Gains and Bids below Variable Cost (VC)

The procedure provides for sharing of 'net gain' by the participating generator with the beneficiary. However, there is ambiguity in terms of its definition. A situation may arise wherein a generator's net VC, after accounting for gains from PLF, is lower than the approved VC. A generator may thus be willing to bid below its VC. Further, a generator may also do so to avoid ramping constraint for the plant. In such a situation, the provision for sharing of 'net gains' should not be construed to be 'netted' against the 'under recovery' from RTM, when a cleared bid being lower than the approved VC. However, this needs to be addressed through Regulatory provisions rather than through scheduling procedure.

'Determination' of Intra-State Transmission/SLDC Charges

In the case the intra-state transmission charges or the SLDC system operating charges have not been determined by the respective SERC, the procedure specifies such charges to be applicable. Legal aspects of such a 'determination' should be reviewed to avoid any issues later.

Standing Clearance by DISCOM/ISGC Generators

DISCOMs, as beneficiary to a generating plant, can bid for their share in a generator. A generator can also trade the URS post schedule revision window. Theoretically, same generation capacity can be traded by either of the entity, the DISCOMs and the generator, in a sequence. Procedure to update the final quantity available with ISGS for trade under RTM and limiting their transactions under RTM to such extent should be clearly specified. Further, an entity can submit its bid on both power exchanges to the extent of standing clearance. Since standing clearances are not exchange specific there is a possibility of final trade for an entity on both exchanges together, being more than the standing clearance, and thereby possibility of schedule over and above the capacity of the generator. There is no process laid out to handle such situation.

Communication Failure and Follow-up Procedure

As the time available for communication between power exchanges and RLDC is limited, the update of power exchange's schedule should be promptly available on RLDC website for crosschecking by power exchanges. In case of communication failure, a small window of 3-5 min for follow-up communication can thus be utilised so that there is no adverse impact on the market outcome and the participants.

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.

A high proportion of sell side liquidity (as compared to buy bids) in the Day-ahead contingency and Intraday transactions is observed (Refer to TAM charts on page 5). RTM, a competitive auction mechanism by design, should be able to attract participation of DISCOMs to ensure that there is sufficient buy side liquidity, further enhancing the competitiveness envisaged through RTM.

Revised Procedure for Security Constrained Economic Despatch (SCED)

The revised procedure provides for violation of ramping and transmission constraints for obtaining the optimal solution to avoid infeasible or non-convergent cases. Impact of such violations, if recurrent, should be scrutinised and addressed appropriately.

From a modelling perspective, violation penalties should at least be equal to the highest VC. Higher penalties are generally recommended. In any case, the highest VC (used in this context) should be rounded to the next Rupee rather than the nearest one, thus ensuring a more optimal outcome.

Opposing ramping requirement across two regions, as mentioned in the revised procedure, should generally assist a solution unless the transmission links connecting the two regions face a constraint.

State beneficiaries are to be billed by their respective generator on the basis of RLDC schedule issued prior to SCED optimisation. SCED settlement provides for adjustment towards part load compensation due to decrement issued to the SCED generators. Such an 'adjustment' should also be provided against 'reduction' in part load operation post increments issued to the generators. Otherwise, beneficiaries face unsymmetrical settlement thereby causing higher burden to the end consumers.

As SCED is closer to the delivery period (in comparison to DAM), in the event of a communication failure in providing the SCED schedule to the generators, the applicability of/waiver from the resultant DSM charges should be clarified.

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.

Revenue sharing mechanism for additional revenue realization by ISGS generators by participating in RTM needs to be specified, such a mechanism should reduce overall cost of power procurement of distribution utilities.

Market monitoring framework needs to be significantly strengthened to ensure that participation across various market segments and those made available through PPA are not gained for the detriment of the procurers, making a long-term dent on the efficacy of the implemented power market design.

As the share of DAM and Short-Term Market increases, the rule of transmission charges for long-term and short-term needs to be revised to ensure that long-term beneficiaries are not overburdened with transmission charges due to increase in share of short-term transaction.

Same DSM framework should be applicable for Conventional and Non-conventional generators with a smaller margin to RE generators in deviation from scheduled power. A deviation of 5% is fairly acceptable.

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.

Proposed Methodology for Compilation of Coal Price Index

Need for Revision in Methodology for Escalation Index: Variation in the coal prices for different grades, as shown below, clearly highlights the need for more representative coal price index for determining the escalation factor.

Laspeyres Vs Paasche index: As acknowledged in the staff paper the Lespeyres index uses base year rates to derive changes in the Price index in a current period. It is suggested that the Paasche index would be more suitable as it uses current period weights. Since the coal cost burden is on account of the current period's coal purchases, Paasche index would provide a better picture of the cost escalation of the coal being consumed in the current billing period.

Weights used for Index: The proposed methodology suggests use of value (price x quantity) as weights to derive the Price index. Adoption of value as weights would overestimate the Price index as costly coal grades would automatically have higher weights. Use of quantities as weights would be more appropriate.

Geometric Average for Base Year Price Index: Geometric mean of monthly prices for the coal price may lead to under-estimation of the true cost of the coal basket.

Deriving Annual Rate from 6 monthly rate (Step 3 clause 8): It would be more appropriate to account for compounding rather than doubling the six-monthly rate to derive annual rate.

Price Index for Captive Coal Mines: Price escalation in coal prices published by CIL are a reflection of its inefficiency. In the case of captive coal mines operated by efficient private or public sector generators, one would expect the operations to be more efficient and should not warrant for a similar level of price escalation.

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.

In the absence of UC, all the units on bar would be allowed to run up to technical minimum along with heat rate compensation, thus imposing a higher overall cost on the system and ultimately the final consumers, whereas SLDCs can opt for shutdown of a unit as well.

In future, SCED should also consider unit commitment taking into account the strategy of shutting down of a unit, particularly under low-demand conditions.

The concept of retrospective changes in the SCED schedule, in the context of infeasible/nonconvergent solution, may expose the constituent to 'Unscheduled' DSM penalty/incentives as its treatment is not specified.

The inclusion of URS in SCED optimisation may leave no economics in it.

The objective function used for SCED (as given in the document) is based on an individual block basis and does not consider optimisation feasible across time blocks where ramping constraints would influence the solution.

There is no provision for passing the baton; provisions for roll-over must be provided through the mathematical formulation.

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.

The legal implications of termination of PPA(s) may be significant, given the high financial stakes for investors and lenders.

A holistic market design should give due consideration to all segments of capacity market, DAM/TAM, Deviation Settlement Mechanism (DSM), RTM, AS, etc. A capacity market to be developed alongside MBED would help ensure long-term resource adequacy.

The implementation of MBED may witness high fixed costs by GENCOs, with lower variable costs for getting scheduled in DAM. Consequently, technologies like solar photovoltaics (SPV), especially with storage, would be the most viable option.

Proposed Bid (Order) Types in DAM - IEX's petition to CERC

The whole bid system is more favourable to the seller side.

The constant quoted price of MQB and PB would be compared with average and weighted average MCP respectively of the block for selection. This may lead to paradoxical rejection in individual time block(s) of the profile.

Bid types such as PB and FB are specifically designed for renewable power plants, but the planttechnology type of bidder, placing such bids may not be known to the market operator. Also, an optimal solution may not be possible if unintended plants use such bids for their own financial benefit.

Minimum quantity bids and MIC bids are contradictory in nature. The former places a lower bound whereas the latter an upper bound on the selection criterion.

Similar products should be combined for a less complex system to ease the process of market clearing and settlement.

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.

For participating in RTM, RE generators would have to be well equipped with more reliable generation forecast.

The RTM would require real time exchange of information on congestion, injection/drawl schedules, cleared price, cleared volumes, etc., between power exchange(s), system operators and market participants.Availability of adequate infrastructure in such regards must be ensured in advance.

With the introduction of RTMs, better market monitoring would be required to avoid the abuse of market power.

CERC - Re-designing of Ancillary Services Mechanism in India

Efficiently designed ancillary services market along with proposed real-time market should ultimately render DSM operation irrelevant.

At the end of the debarment period, an evaluation process should be put in place to strengthen compliance framework for debarred participants to regain entry in the Ancillary Services market. Failure in qualifying the evaluation should lead to extension in the debarment period.

Based on relative technical capability, inter-/intra-state plants/facilities participating in ancillary services market should be classified into Ramp Resources, Ramp Limited Resources and Energy Limited Resources.