RDSS-Smart Metering- Key Risks and a Lost opportunity for the Smart Grid

Background

RDSS has been launched with a noble objective of enhancing the quality, reliability, and affordability of electricity delivery to consumers by fostering financial sustainability and operational efficiency within the Distribution Sector, achieve nationwide AT&C losses within the range of 12-15% by the fiscal year 2024-25 and attain a zero-gap between the ACoS and ARR by the fiscal year 2024-25. Since its launch, RDSS scheme & SBD have been amended several times to incorporate new conditions.

The scheme comprises of metering, Distribution infrastructure, project management and capacity building with an outlay of Rs.3.03 Lac Crore and GBS of Rs 97,631 Crore (around 32%). The primary emphasis of the program lies in Advanced Metering Infrastructure or smart metering, aiming to deploy 25 Crore pre-paid smart meters systematically under TOTEX (CAPEX+OPEX) under DBFOOT model by 2024-25 in all consumer premises, excluding Agriculture consumers. This directive is in accordance with the Ministry of Power Notification No. 23/35/2019-R&R dated August 17, 2021. In the scheme, the average unit meter cost has been provisioned as Rs.6000 with 15% subsidy capped at Rs.900 per unit making total provision more than 1.5 Lac Crore. The OPEX payment to AMISP (Advanced Metering Infrastructure Service Providers) by the discoms will be on successfully managing the system for 93 months after its installation. Besides AMI, the scheme also includes components relating to Distribution Infrastructure, Project Management and Capacity Building. Therefore, the success of the RDSS scheme primarily hinges in the success of smart metering rollout for consumers as well as Distribution Transformers.

Currently, there are 51 AMISP registered with most of them not having any experience of working with the discoms and are primarily aggregator/integrator of different components of the scheme. As per the National Smart Grid Mission, so far installation of around 17.5 Crore meters have been approved under RDSS scheme out of which orders have been placed for 7.26 Crores and deployment have not started in most states and signing of SLA is delayed due to various issues.

Benefits

Smart Metering offers tremendous technical advantages to the grid stakeholders. The discoms are benefitted by way of:

a)      Improving Billing Quality.

b)      Remote Disconnection/Reconnection for arrear recovery from defaulters.

c)       Real time information of Outage, resulting in timely redressal.

d)      Remote intelligent data analysis (pinpoint irregularities

e)      Identification of theft prone areas/consumers based on smart data analytics.

f)       Effective System health monitoring.

g)      Better monitoring of Billing, Collection, and Supply Management etc. with more reliable and near real time data.

h)      Feeder/DT wise energy accounting and better planning for reduction in AT&C Losses.

i)        Support for load forecasting and regulatory compliance

 The Load Dispatch Centers (LDCs) derive several advantages through enhanced capabilities in demand analysis, energy forecasting, and peak load management. This leads to improved supply reliability, fostering better communication of energy and billing data to consumers. This upgraded supply system empowers consumers by enabling them to monitor consumption patterns, billing information, and provides opportunities to engage in incentive programs.

Regulators benefit from access to reliable statistics, which aids in efficient planning and tariff determination. This data is instrumental in designing innovative initiatives such as Demand Response, Storage, Time of Day (ToD), and Time of Use (ToU) tariffs. Additionally, regulators can easily monitor Standards of Performance, System Average Interruption Duration Index (SAIDI), and System Average Interruption Frequency Index (SAIFI). This robust information infrastructure facilitates the introduction of innovative services like peer-to-peer energy transactions and behind-the-meter services.

In essence, the AMI or smart metering and data-driven insights not only enhance the operational efficiency of LDCs but also empower consumers and regulators, fostering a more dynamic and responsive energy ecosystem.

Critical Assessment

While the technical and financial advantages of rolling out smart meters into the distribution sector are evident, the success of this initiative relies on a thorough process of identifying, assessing, quantifying, and mitigating all associated risks related to legal, technical and financial dimensions to ensure an acceptable cost-benefit ratio. Unfortunately, some significant risks still lack adequate mitigation measures. To illustrate these risks, I will delve into the specific statistics of Uttar Pradesh discoms to evaluate the likely success of the scheme.

1.       Exclusion of Smart Grid as an Objective

India has undertaken a National Determined Contribution (NDC) commitment to attain 50% of its installed capacity from non-fossil fuel-based energy sources by 2030. Simultaneously, it has set an ambitious Renewable Purchase Obligation (RPO) target, aiming to achieve 43.3% of its total energy from renewable sources by the same year through the installation of 500 gigawatts (GW) of renewable energy sources. Although there is a disconnect between the target of achieving 50% installed capacity as per NDC and 43.3% energy through RPO because the CUF of renewables is much lesser, but that aspect can be ignored for the time being .

As the fundamental structure of the grid transitions from the traditional base load and peak load based plants to a more flexible model involving Distributed Energy Resources (DERs) and Electric Vehicles (EVs) etc., there is a pressing need for large-scale integration of distributed renewable energy resources. Effectively managing this evolving grid requires the implementation of a smart grid, which incorporates intelligent components such as smart meters, Supervisory Control and Data Acquisition (SCADA) systems, sensors, and more. In essence, the deployment of a smart grid infrastructure becomes a critical enabler for achieving India's renewable energy targets. However, the RDSS scheme is focused on only reducing AT&C losses through smart pre-paid meters and includes only a small insignificant component for training / Smart Grid Knowledge Center by way of GBS of Rs. 30 Crore to CPSU Power Grid and does not encompass the broader scope of a smart grid even when a huge sum of more than 3 Lac crore is proposed for the scheme.

2.       Inadequate funding and no burden sharing amongst the stakeholders

The scheme outlines the installation of 25 crore meters with an average cost of Rs. 6000 per unit, including a GoI subsidy provisioned at Rs. 900. However, due hto the compressed time frame and other conditions of the Standard Bidding Document (SBD), the discovered bidding prices have escalated by an average of 30%-35%. In the recent bidding for Uttar Pradesh's distribution companies (discoms), encompassing 9 clusters, the discovered prices ranged from Rs. 7307 to Rs. 8428 per unit. The total cost amounted to Rs. 29,612 Crores, surpassing the RDSS DPR estimate of Rs. 21,834 Crore by 35.66%. This additional expenditure of Rs. 7785 Crore, equivalent to about 3.5 years of admissible Return on Equity for the discoms, has to be funded by discoms itself as no financing is available from the scheme beyond the DPR. The discoms also face the challenge of being unable to pass on the smart meter costs to the consumers since regulators contend that consumers have already paid for the meters cost while taking connection and can’t be forced to pay again. Furthermore, a Ministry of Power letter (F.No.14/02/2021-UR&SI-II-Part(1)(E-258136) dated 16 Sept.23) exempts consumers from any payment towards smart metering costs.

GoI subsidy @ 15% with the ceiling of  Rs. 900 per unit, which discoms have to pay on the Operational Expenditure (Opex)  to the AMISP works out to be less that the 18% GST it pays on the average cost of Rs. 8000 per unit. Consequently, the entire burden of increased smart metering costs has to be borne by the discoms, and its recovery through efficiency gains from improved billing and collection ratios may prove challenging.

3.       Disproportionate high Cost for AT&C Reduction

The notion that smart pre-paid metering will effectively curb AT&C losses and yield financial benefits for discoms poses a significant challenge and is contingent upon the consumer’s consumption profile. In Uttar Pradesh (UP), under SAUBHGYA scheme, over 1.2 crore consumers were added, most of which falling into the Lifeline category. As per audited Trued up statements for FY 2021-22, the number of Lifeline consumers in UP is 1.45 Crore, constituting approximately 45.3% of the total consumer base of 3.21 Crores.  The total energy consumption of these lifeline consumers was 11.893 billion units (12.68% of the discoms total energy consumption) with an average of 68 units per month and their average electricity bill remained below Rs. 300. Further, as per the discovered price through bidding, discoms are obligated to pay approximately Rs. 80 per meter per month, translating to more than 25% of the revenue collected from these Lifeline consumers who pay monthly bill of less than Rs.300 and constitute around 45.3% of discoms consumers. This is in stark contrast to the discoms' average AT&C loss, which was around 20%. So, in a way, if smart pre-paid meters are installed in these lifeline consumers’ premises, the cost of these meters will be more than 25% of revenue from these consumers. The issue is not unique to UP only as many states that have also added Lifeline consumers under the SAUBHGYA initiative and may encounter similar challenges, potentially jeopardizing the financial viability of the Advanced Metering Infrastructure (AMI) program.

If the primary objective is to instill financial discipline and mitigate AT&C losses through improved collection methods, traditional pre-paid meters, at a 1/4^th of smart meter’s cost per unit, could have justified the cost benefit, however higher financial cost for the Advanced Metering Infrastructure can only be justified with the technical and economic benefits by the smart grid objectives and not merely with AT&C loss reduction.

4.       Gaps in Target categories and One Size Fits all Approach

The Ministry of Power (MoP) notification dated 17-Aug-2021 has granted an exemption to Agricultural consumers from the mandatory use of smart pre-paid meters. It is noteworthy that in many discoms partly camouflage higher AT&C losses by showing them as unmetered agricultural consumption to avail agriculture subsidies from the government. Metering agricultural consumers is necessary for energy accounting and targeted subsidy/DBT etc. Excluding agricultural consumers from the mandatory use of smart meters will only serve to perpetuate this anomaly. Moreover, as the scheme is centralized, it adopts a one-size-fits-all approach for discoms, despite variations in consumer profiles, load duration curves, capacities, and other factors influencing AT&C losses across different regions.

5.       Legal Risks- No Choice to the consumers and takes away their  grievance rights

The Smart Pre-Paid metering system under RDSS faces risks associated with specific provisions of the Electricity Act 2003 that remain un-mitigated. For instance, Section 47(5) includes a provision implying consumer consent for pre-paid metering, stating, "if the consumer is prepared to take supply through pre-payment meter." However, both the Ministry of Power (MoP) notification and the Scheme have removed the consumer's option of choosing "pre-payment" and instead made it mandatory. It is noteworthy that businesses in distribution, such as telecom, typically provide consumers with the choice in this regard.

Likewise, the provision for mandatory prepaid meters installation also conflicts with Section 56 of the Act, which mandates a minimum 15 days' notice before disconnection even in case of non-payment of bill. This essential feature is currently absent in the scheme. Denying consumers this right would impede their ability to dispute erroneous bills, a right expressly granted under the Act. Besides these, the technical and regulatory challenges exist in providing net metering connections to the consumers under rooftop solar schemes through compulsory pre-paid smart meter mode.

6.       High Financial Risk for AMISP

Although Rs. 1.5 Lac Crore has been earmarked under RDSS for smart metering, the unit prices discovered in the bidding process suggest that the anticipated project cost for installing 25 Crore meters will exceed Rs. 2 Lac Crore.  AMISPs have to provide this on DBFOOT model for around 10 years concession period.  Thus, the AMISPs are exposed to a long duration of financial risk related to steeper penalties for their non- performance of long list of obligations, faulty meters under warranty etc.. It may be noted that while BIS provides of manufacturer warranty of 5.5 years, RDSS demands warranty for the duration of concession i.e. around 10 years adding on to the cost of project.

Moreover, a significant number of AMISPs possess a limited equity base and are resorting to higher leveraging. The inadequate financial capacity or lack of willingness of  consumers especially the lifeline consumers  to meet their payment obligations may result in the disconnection of their supply, pose a risk of shrinking revenue streams of discoms and, consequently, to the AMISPs, as no supply translates to no payment. This situation could potentially expose their lenders to non-performing assets.

7.       Technology Risk for AMISP

The cost of smart meters supply is only an event in the overall project, with the predominant focus on the process of operation and maintenance of associated IT infrastructure over the concession period. In this regard, the role of IT especially the telecom plays an important role. The diminishing footprint of GPRS technology raises concerns about its effectiveness, and the initial lower cost of 2G communication may give rise to operational challenges in the future. With approximately 60 crore smartphones, characterized by high Average Revenue Per User (ARPU), dominating the spectrum usage, the introduction of an additional 25 crore GPRS/GSM/VoLTE/5G  based smart meters could lead to heightened competition for spectrum resources, potentially escalating communication charges. Moreover, a parallel development observed in Europe underscores the risk of hidden costs related to Intellectual Property Rights (IPR) fees, with technology companies claiming ownership of IPRs in 3G, 4G, 5G, and NB IoT technologies and thereby exposing AMISPs to these risks.

As grid operations evolve towards increased flexibility and real-time responsiveness, the true advantage of smart meters lies in retrieving consumer data every 15 minutes, if not every 5 minutes. However, with 25 Crore consumers, even at a 15-minute interval, a substantial volume of data will be generated. Effectively managing  this vast dataset while complying with the data privacy laws and ensuring robust cybersecurity measures will present a formidable challenge for AMISPs in fulfilling their obligations.

Conclusion

In conclusion, the objectives of RDSS Smart meters should go beyond only reducing AT&C losses, as these gains are achievable through conventional pre-paid meters as well at a much lower cost. The objectives should encompass smart grid to justify the high cost with associated higher benefits of smart grid. The smart grid will facilitate flexible generation, distributed renewable energy source integration, and effective load management. The rollout should strive to unlock the full spectrum of smart grid features, providing technical advantages for discoms, consumers, grid operators, and regulators, contributing to the overall efficiency, reliability, and sustainability of the electrical grid.

 The limited supply of meters and a shortage of technically proficient personnel, the expedited smart meter rollout within a condensed timeframe has led to increased costs, making the cost-benefit ratio unviable. Therefore, it is recommended to extend the rollout duration to effectively address these challenges and reduce the implementation cost and enhance the technical benefits.

Smart meters offer potential for targeted subsidization, but the current grant allocation is insufficient. It is crucial for the State/Central Government Grant to be increased, covering a minimum of 50% of the cost. This augmentation is essential to align with the National Determined Commitment of de-carbonization through renewable integration, extending funding beyond ratepayers to include taxpayers. Lastly, to ensure inclusivity, comprehensive coverage should be extended to all consumer categories without any data exclusions and private discoms should also be deemed eligible under RDSS to achieve complete coverage and maintain a fair playing field.

 

The Surprising Truth of CO2 Emissions of Efficient ICE Cars and EVs in India

India stands at the crossroads of an environmental revolution, with an escalating focus on decarbonisation and sustainable transportation. The shift from conventional ICE vehicles to electric vehicles (EVs) is perceived as a monumental stride toward curbing carbon emissions. However, a closer inspection of the present scenario might astound us. In this blog post, I will meticulously compare the CO2 emissions of efficient petrol and diesel cars with the current generation of EVs in India, spotlighting a pivotal but often overlooked factor—the carbon footprint of the electricity grid.

The Green Grid Illusion:

Despite being heralded as eco-friendly alternatives, the carbon footprint of EVs heavily hinges on the electricity source. In India, where coal-fired power plants still dominate the energy landscape, the electricity grid is far from being entirely eco-conscious. Despite strides in renewable energy, a substantial chunk of India's electricity is derived from fossil fuels, leading to CO2 emissions.

Analysing the Grid:

	Total	Avg. Co2 emission	Co2 emission	Co2 emission factor
	Generation 22-23	factor		of Indian Grid
	(Billion Units)	(Kg Co2e/kwh)	(MT)	Kg Co2/Kwh
Coal & Lignite	1078	0.95	1024.1
Oil	115	0.75	86.25
Gas	37	0.54	19.98
Nuclear	47	0	0
Hydro	161	0	0
Solar	74	0	0
Wind	69	0	0
Bio-Mass	16	0.9	14.4
Others	3	0.8	2.4
Total	1600		1147.13	0.72

 

Efficient ICE Cars and Common EVs

While BS VI emission standards target only pollutants like NOx, PM, HC, and CO,however these stringent limits encourage the adoption of efficient technologies, leading to reduced CO2 output per km. Currently, an efficient Strong Hybrod petrol car producing 2.64 kg of CO2 per litre and covering 25 km per litre emits approximately 0.105 kg of CO2 per km. Similarly, an efficient diesel car emitting 2.39 kg of CO2 per litre and running 20 km per litre emits 0.12 kg of CO2 per km.

Conversely, numerous popular EVs in India actually offer an average range of 6-7 km per kilowatt-hour (kWh) of electricity. Given an electricity grid emitting 0.72 kg of CO2 per kWh, these EVs emit approximately 0.102 -0.12 kg of CO2 per km. These emission figures are remarkably close to their petrol counterparts.

The Surprising Equivalence:

When comparing the CO2 emissions of efficient Strong Hybrid petrol cars (0.105 kg CO2/km) and common EVs in India (0.102-0.12  kg CO2/km) in light of the current grid's emission factor, the numbers are almost identical. This startling parity underscores the urgency of addressing the electricity grid's carbon footprint, a facet often overshadowed by the spotlight on EVs.

Conclusion:

Undoubtedly, EVs hold the key to a sustainable future, but their impact on reducing CO2 emissions is only as potent as the environmental friendliness of the grid powering them. As India progresses toward a greener tomorrow, accelerating the shift to renewable energy sources is imperative, rendering the grid genuinely eco-friendly. Moreover, enhancing the efficiency of EVs is essential. Only then can EVs realize their full potential as low-emission alternatives, making a substantial impact in the fight against climate change. Understanding the intricate relationship between vehicles and the grid is pivotal for informed decisions that guide us toward a truly sustainable future.

 

 

 

 

 

 

Prospects & Pitfalls of Power Market Coupling in India

                           A market reform in the Indian power sector is overdue as market is stagnated at less than 10% of total generation. Out of the total market size of around 1500 TWhr, the share of exchange-traded electricity is a meagre 7%, or around 100 TWhr, and the remaining portion is transacted through long-term bilateral Power Purchase Agreements (PPAs) or on Over-the-Counter (OTC) platforms such as DEEP or PUShP, among others. The forward market (settlement against physical delivery) and derivatives (futures - where only financial settlements take place) do not exist as they are yet to be approved by CERC or SEBI, respectively. Currently, three Power Exchanges (PXs), namely Indian Energy Exchange Ltd. (IEX), the Power Exchange of India Ltd. (PXIL), and the Hindustan Power Exchange Ltd. (HPX), are operating under the framework of PMR 2021, with IEX being the dominant one, accounting for around 89% of the total exchange-traded volume.

A CERC staff paper has been floated in August '23, soliciting views on the Introduction of Power Market Coupling. Market Coupling has been defined as the process whereby collected bids from all the Power Exchanges are matched, taking into account all bid types, to discover the uniform market clearing price for the Day Ahead Market, Real-time Market, or any other market as notified by the Commission, subject to market splitting.

The stated objectives of Market Coupling include the discovery of a uniform market clearing price for the Day Ahead Market, Real-time Market, or any other market as notified by the Commission; optimal use of transmission infrastructure; maximization of economic surplus, after taking into account all bid types, and thereby creating simultaneous buyer-seller surplus. However, the real concern appears to be the limited market share of the two PXs other than IEX. Regulatory intervention to change market design to increase volume of non-performing power exchanges is highly unjustified. 

The staff paper has outlined the Market Coupling Operator as an entity notified by the Commission for the operation and management of Market Coupling. Subject to the provisions of the regulations, the Commission shall designate a Market Coupling Operator who shall be responsible for the operation and management of Market Coupling. The word “notified” indicates that either an ex-officio person or institution is intended to be notified as MCO. The probability of an institution like GRID INDIA (formerly known as NLDC or POSOCO) being selected appears to be higher.

A Comparative Analysis: EU vs. India Power Market

The concept of market coupling was initially introduced in the EU power market with the primary objectives of integrating different geographical markets (countries) and optimizing cross-border transmission infrastructure. This integration aimed to achieve price convergence between these integrated markets. Market coupling in CWE and NWE actually began as Price Coupling of Regions (PCR) with a collaborative approach initiated by the Transmission System Operators (TSOs, which own and manage the transmission system) and the Power Exchanges (PXs) of the regions/countries. Price coupling of regions in Europe uses common algorithms and IT standards for PXs. The European power market comprises many exchanges such as EEER, Nord Pool, etc., operating across numerous EU countries. These exchanges are also designated as nominated Electricity Market Operators (NEMO), and the volume of power traded on these exchanges is high, both in terms of size as compared to India. For example, around 5197 TWhr of energy was traded on EEX in 2021, out of which 629 TWhr was in the spot market, and the remaining 4568 TWhr was in the derivative segment. Similarly, on the Nord Pool exchange, 1077 TWhr of energy was transacted. European countries/regions like Germany have exchange-traded power shares as high as 60%, while other regions (Nordic, etc.) typically maintain a share of 25%-30%.

In the European exchanges, regions are divided into bidding areas by the relevant TSOs to manage congestions in the electricity grid. Bidding areas can have a balance, deficit, or surplus of electricity. Electricity flows from areas where the price offered is lower towards areas where demand is high and the price offered is higher. If the transmission capacity between bidding areas is not sufficient to achieve full price convergence across the areas, congestion can lead to bidding areas having different prices. If the flow of power between bidding areas is within the capacity limits set by the transmission system operators, area prices in these different bidding areas will be identical. All suppliers/producers are paid according to the calculated area price, and similarly, all consumers pay the same price. The exchanges also determine the System Price, which is an unconstrained market clearing reference price for the region. It is calculated without any congestion restrictions by assuming transmission capacities to be infinite.

Flows between the regions, as calculated through area price calculations, are taken into account in the system price calculation. These flows are used when calculating the System price, either as import/sales or as export/purchase orders. Most standard financial contracts (futures) traded in the region use the System price as their reference price for settlement.

On the other hand, in India, there is no concept of a Transmission System Operator (TSO) as Grid India (formerly NLDC/POSOCO) is the authorized Independent System Operator (ISO). We have a national grid, and for trading purposes, it is divided into 13 bidding areas with interconnected transmission systems. The power market operates on a voluntary model where three PXs operate at the national level only, and around 7% (~ 100 TWhr) is traded on PXs with different prices for different areas in different PXs. In fact, the proposed Market Coupling for the Indian market primarily equates to 'price coupling' of different power exchanges. As a result, market coupling in India would only apply to approximately 7%, leaving the remaining 93% of energy with varying prices under PPAs. Above all, unlike the European market, the proposal to introduce market coupling is not a collaborative initiative of the three PXs with the objective to integrate different geographies.

Challenges and Concerns

Under the proposed coupled power exchanges, existing power exchanges (PXs) would function as intermediaries and merely collect the bids, forwarding them to the Market Coupling Operator (MCO) for price discovery and conveying the price discovery results and cleared transactions. This arrangement, besides being anti-competitive, would provide power exchanges with no incentives to improve their product offerings, innovate, or further develop the market. Consequently, it could negatively impact investment flows and hinder market development. On the other hand, the MCO, being a monopoly entity without direct customer interaction, would lack incentives to introduce innovative products. This may be the main reason why the financial securities regulator SEBI has not implemented market coupling for security trading exchanges like NSE, BSE, etc. as arbitrage in price of securities between the exchanges enhance the competition and market efficiency.

In the Indian context, the objectives of market coupling are largely fulfilled, as all regions are already geographically integrated, utilizing a common transmission infrastructure efficiently.  Introducing a centralized market setup with a single entity or MCO would come at a cost in terms of time and resources.

Indeed, market coupling not only discourages innovation but also narrows the competitive landscape to focus solely on pricing, side-lining the crucial aspect of deepening market volume, which is integral to market development. Instead of striving to enhance market share through inventive and customized trading solutions and products, Power Exchanges (PXs) may resort to capitalizing on their competitors' resources, investments, and innovations. Within such a framework, PXs may become hesitant to invest in future innovations. In summary, this approach represents a regressive step in terms of fostering healthy competition among exchanges and instead of fostering innovation and competition, the proposed introduction of market coupling might inadvertently promote free-riding behaviour.

While official regulations regarding this matter are yet to be published, designating an entity as a Market Coupling Operator (MCO) carries significant implications. The Indian power market differs notably from its European Union counterpart. In the European Union, Transmission System Operators (TSOs) play a pivotal role in coupling exchanges to facilitate power flow between interconnected regions (countries) and in settling financial products, including future contracts. In contrast, India currently lacks financial products of this nature and does not have TSOs in its framework. Instead, the country relies solely on Independent System Operators (ISOs) or GRID India (formerly NLDC or POSOCO), which are entrusted with grid management functions under Section 26 of the Electricity Act.

It is worth noting that GRID INDIA or NLDC is explicitly prohibited from engaging in the trading business as per the first proviso of Section 26(2). This prohibition raises concerns about potential conflicts of interest, particularly in their involvement in price discovery, which is an integral part of trading. An ISO, when designated as an MCO, shall face a significant conflict of interest, as it could seek to benefit from cost savings in its ancillary services, which occur after the gate closure of bids and balancing.

Furthermore, the transfer of competences and jurisdiction from exchanges to a System Operator, whether independent or not, may not be an advisable course of action before meticulously evaluating the consequences of such a transition, as it is perceived as anti-competitive and has the potential to introduce complications and challenges that might undermine the efficiency and fairness of the market.

The methodology employed in price discovery algorithms will serve as the linchpin of the entire process and will ultimately dictate whether market coupling can effectively yield a genuine market surplus. Consequently, there arises a necessity to develop a new, shared algorithm to underpin the implementation of the market coupling framework. This will necessitate a complete reset, effectively nullifying the investments made by exchanges thus far, as well as the knowledge and experience garnered by the trading community, encompassing both buyers and sellers, along with institutions.

The involvement of a third party as an MCO could lead to discrimination, with potential adverse effects on Power Exchanges (PXs). The designated MCO may operate without requiring a license or paying license fees, while still benefiting from a share of PXs' trading revenue and capitalizing on their innovations. Introducing an additional entity into the process after the bidding gate closures and the actual clearing/dispatch stages could result in increased time and costs for market participants. As renewable energy (RE) penetration continues to rise, the efficient management of Real-Time Markets (RTM) will become even more crucial for the further development of the market.

Establishment of an MCO could potentially lead to a single point of market failure, as it may stifle the development of diverse systems for short-term electricity markets that could serve as backup solutions. It's important to note that activating demand reduction by ISOs before the balancing timeframe could distort intraday market prices, which should ideally remain the primary signal for the efficient development of flexibility solutions. Similarly, sponsoring unsubstantiated benefits of Market Coupling with SCED (Security constrained economic dispatch) are deceptive as Indian power market is voluntary and mixing with SCED would tantamount to interfering with price discovery under section-63 and will have legal and regulatory consequences in terms of its adoption.

To further develop the power market, particularly in anticipation of the integration of significant solar and wind energy generation capacity, it is necessary to introduce innovative market products. However, it is also essential to exercise caution when contemplating the introduction of Market Coupling with electricity forward markets (with physical delivery obligations) and derivatives.

Conclusion

The current circumstances do not favour the introduction of market coupling in Indian power exchanges solely for the purpose of price discovery. Market coupling, even if implemented, is unlikely to have a significant impact on electricity transaction prices in India due to the relatively low share of exchange trade and entire volume with one exchange. Introduction of Market Coupling at current stage and shape will disrupt the sequence of power market reforms. Implementing market coupling before achieving a substantial market share of exchange-traded power is unlikely to add value, enhance market depth or increase social welfare. Moreover the high implementation costs and the risk of market disruption and failure, make it counter-productive. It could potentially increase operational expenses, introduce inflexibilities, and stifle innovation within the market.

Instead, focus should be on increasing the volume and share of electricity traded in the PXs and increasing the inter-regional transmission capacities to reduce the congestion and constraints. Reduction of constraints in transmissions is likely to yield more benefit as area clearing price will tend towards the unconstrained System Prices. While products like G-TAM (Green Term Ahead Market) and G-DAM (Green Day Ahead Market) hold significant potential, relying solely of current shelf of products to raise the exchange trade share to the optimal level of 25-30%, will take many years. Therefore adding new products including forward market & derivatives is essential to deepen power market and without these, the proposed Market Coupling is not likely to achieve any objective and provide any benefit to either exchange participants or end consumers.