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.

The Future of Discoms in a Green Electricity World

                                                                                     The distribution business plays a pivotal role in the power supply chain and serves as the cornerstone for the financial sustainability of the power sector. However, over time, while there has been significant growth in generation and transmission capacity and investment, the distribution business has evolved into a cost centre, exerting a detrimental impact on the economy due to its precarious financial state. Several factors contribute to the poor financial health of distribution companies (discoms), including governance deficiencies, high aggregate technical and commercial (AT&C) losses, regulatory inertia leading to delayed tariff orders, unregulated coal prices, escalating railway freight costs, delayed subsidy disbursements, increased government intervention, and stagnating energy demand. Nevertheless, I view discoms as an integral part of the solution in our pursuit of a cleaner environment, rather than being a part of the problem.

The first generation of reforms in the power sector, ushered in by the Electricity Act of 2003, brought about significant changes. It deregulated power generation and separated transmission from generation activities. However, the unbundling & restructuring of distribution was postponed for a later phase. Initial reforms aimed to distance both state and central governments from technical and financial matters by establishing independent regulatory commissions at both levels.

Furthermore, the deregulation of power generation, particularly through the Regulated Tariff Mechanism (RTM) and the provision of a high Return on Equity (RoE), resulted in an excessive surplus of power generation capacity. This surplus arose from overly optimistic demand projections by the authorities, leading to the creation of stranded generation capacity. The situation worsened due to the inclusion of low-income consumers in the "power for all" initiatives and the implementation of more stringent Renewable Purchase Obligation (RPO) targets for states, which mandate the purchase of renewable energy on a priority basis, even when it surpasses actual demand growth. These factors have increased the accessibility and availability of power but have come at the expense of affordability. Consequently, this has had detrimental effects on the financial health of distribution companies, which has now become a pressing issue for the entire power sector. Earlier, flexible load of the grid was served by stable base load and peak load plants. This all is now changing rapidly now due to more and more decentralised renewables having variability & intermittency and spread over geographical areas are getting integrated with the grid and thereby making the need of flexibility in the grid , a real necessity and grid balancing an expensive and complex operation.

Renewable energy sources such as wind and solar are inherently location-specific and often situated at considerable distances from major load centres. This geographical dispersion necessitates substantial investments in the development, expansion, and upgrading of high-cost transmission networks, as well as the implementation of advanced network management techniques or the utilization of Virtual Transmission through Energy Storage Systems (ESS). Besides , there's a growing trend towards decentralized distributed renewable energy integration, especially through rooftop solar photovoltaic (PV) systems, whether through gross, net billing & net metering, and the adoption of EVs as a load and distributed source, both.

The evolution of a "Green Grid" can be understood from several key perspectives. First and foremost, the grid must have the capacity to seamlessly integrate a substantial volume of renewable and environmentally friendly energy sources. Simultaneously, it should prioritize safety, reliability, heightened system efficiency, and increased utilization of grid assets. These essential aspects come with associated costs. For instance, the greater intermittency and variability of renewable energy sources necessitate enhancements in grid system operations. This includes improvements in forecasting, scheduling, and dispatch frameworks, the strategic curtailment of renewable energy, and the operationalization of ancillary services such as voltage support, frequency support, and the provision of upward and downward reserves, all with rapid response capabilities.

These ancillary services characterized by their ability to ramp up or down quickly, can be furnished by sources like gas, hydroelectric power with storage capabilities, and batteries. Energy storage systems (ESS) can be integrated either directly with wind and solar plants or strategically positioned at optimal locations within the generation, transmission, and distribution segments of the grid. Their integration serves to further enhance grid security, reliability, and stability, offering one or more critical functions such as energy shifting, fast frequency response, spinning reserve support, frequency regulation support, and ramp rate control support.

The central point to emphasize here is that the integration of renewable energy into the grid comes with associated costs. These costs are initially borne by distribution companies (discoms), and they are later recovered from consumers. Consumer affordability is a crucial consideration in this context and depends on factors such as disposable income and per capita income, which vary from state to state. Consequently, it's impractical to enforce the same standards and timelines as those in developed nations on lower-income states. Ultimately, the per capita income of a state will determine its ability to absorb the costs associated with clean energy. Addressing these multifaceted considerations is essential before large-scale grid integration of renewables can effectively take place.      

The recently introduced Renewable Purchase Obligation (RPO) framework presents us with the challenge of achieving a significantly higher share of renewable energy (RE) by 2030. The new target is set at 43%, including hydroelectric power, compared to the current level of approximately 20%, which includes hydro sources. Presently, the RE capacity, including hydro, stands at around 174 GW, accounting for 42% of the total capacity of 418 GW. However, this capacity translates to only about 20% of the energy generated, which amounts to approximately 316 billion units (BU) out of a total of 1,624 BU generated in the 2022-2023 period. The lower Capacity Utilization Factor (CUF) of existing solar and wind power plants, at roughly 22% and 40% respectively, means that achieving the RPO target of 43% energy from RE sources will require a capacity share of at least 65% to 70% from these sources. This necessitates frontloading an excess capacity approach.

However, this approach may result in us being locked into relatively inefficient technology for the entirety of its life cycle, as we frontload RE capacity additions. This, in turn, could increase the overall cost of transition, reduce affordability, and have adverse effects on the financial viability of distribution companies (discoms). A one-size-fits-all approach to RPO may not succeed, especially as an unfunded mandate.

Furthermore, this approach appears contradictory to our stance at COP26 within the UNFCCC on climate change. At COP26, we emphasized the principle of "equity and common but differentiated responsibilities and respective capabilities" and committed to reaching 50% capacity from non-fossil fuel sources in our Nationally Determined Contributions (NDC). However, domestically, we seem to be moving differently,  affecting our national interests in terms of growth and development.

The recent amendment to the Right of Consumer Rules in 2023 has introduced the concept of Time of Day (ToD) tariffs, slated to take effect from April 1, 2025. However, this amendment has inadvertently set distinct surcharge and discount in tariff for domestic and Commercial and Industrial (C&I) consumers during the peak hours and solar hours respectively. This distinction overlooks the fact that such differentiation may unduly favour C&I consumers, given that their demand is elastic and  predominantly daytime-oriented, while it could potentially burden domestic consumers, who typically have inflexible or in-elastic demand patterns characterized by the use of lighting, fans, and cooling during the evening and night. It's worth noting that regardless of these, the revenue from tariffs have to be subsequently trued up after finalizing accounts.It is also essential to recognize that C&I consumers serve as the cross-subsidizing category, rather than being the recipients of subsidies.

Interestingly, on September 1, 2023, when the grid recorded its highest demand at 239.9 GW at 12:22 hours, regions such as the Northern Region (NR), Western Region (WR), and Southern Region (SR) experienced peak demand that coincided with solar hours. Conversely, regions like the Eastern Region (ER) and North Eastern Region (NER) saw their peak demand occurring in the evening. Moreover, within these regions, states with significant domestic consumer loads, such as Uttar Pradesh in the Northern Region, experienced their peak demand during the late evening, not aligning with either the national peak or regional peaks.

It's important to emphasize that the successful implementation of ToD tariffs necessitates 100% smart metering. However, the current penetration of smart meters remains at less than 10%, presenting a substantial challenge in fully realizing the potential of ToD tariff structures.

Furthermore, a recent meeting of the Forum of Regulators (FOR) on the Resource Adequacy framework underscored a critical concern. It revealed that the current dispatchable capacity available in the country might fall short of meeting the escalating peak and energy demand of the economy in the next 3-4 years. This situation poses a substantial energy security threat, given that the current path of renewable energy integration without storage may not be sufficient to cater to the projected demand and energy requirements.

Turning our attention to the Discoms, which serve as the primary vehicle for propelling our journey towards a green grid, it's important to acknowledge that they are currently the weakest link in the power supply chain. This weakness poses a significant challenge to attracting investments for India's renewable energy sector, which seeks investments totalling $225-250 billion to achieve a generation capacity of 500 GW by 2030.

Discoms must undergo a transformation and embrace the "3 Ds": De-centralization or the incorporation of distributed and flexible energy resources; Digitalization involving the bi-directional flow of information and power through smart meters, SCADA systems, real-time monitoring and control, artificial intelligence, machine learning, and block-chain technology; and De-carbonization through increased integration of renewable energy sources.

To achieve this transformation, a re-evaluation of our policies and the strengthening of our institutions are imperative, as the current policy and legislative framework do not adequately address these new aspects. Therefore, we urgently require the next generation of power sector reforms to facilitate higher-level integration of renewable energy, ensuring the provision of reliable, high-quality, and affordable power for sustainable economic growth. These reforms must address both technical and financial challenges comprehensively.

In India, the distribution business predominantly consists of state-owned natural monopolies, which need to be unbundled into carrier and content entities. This unbundling is crucial because most other network-based industries in the country have evolved in a similar manner and have successfully attracted private investment, such as in the telecom, broadcasting, highways, and gas sectors. Attracting private investment in the distribution sector should be a priority to prevent overwhelming financial burdens on the states, which may lack the fiscal capacity to sustain the grid.

While environmental considerations are of paramount importance as a global public good, it's equally essential to ensure a just transition that balances economic growth and environmental protection. However, there is an increasing intrusion of political science into the power sector, resulting in policies like Renewable Purchase Obligations (RPO) for current inefficient technologies like green hydrogen (RTE < 50%), funded by ratepayers rather than taxpayers. This socialization of costs through discoms affects affordability and adds a significant technical and financial burden to their role in the clean energy transition.

To survive and fulfil their mandate, Discoms must excel in both governance and financial management through tariff and non-tariff measures. On the governance front, achieving 100% feeder segregation and implementing smart metering at all levels, including distribution transformers, is crucial. Tariff-based measures involve improving coverage ratios, maintaining updated consumer databases, and enhancing billing and collection efficiency. Non-tariff measures include capitalizing on digital assets like consumer databases, offering value-added services such as behind-the-meter distributed asset management, rooftop solar power generation, and sharing distribution assets for telecom and broadband services on a revenue-sharing basis. Other opportunities include providing EV charging services, establishing a platform for peer-to-peer energy trading, and collaborating on sub-station infrastructure for various services.

Discoms are the backbone of our decarbonisation efforts, the conduit for the adoption of electric mobility (Battery Electric Vehicles or BEVs), and the enabler of the clean energy transition for industries (such as Green Hydrogen or Green Ammonia). Strengthening this institution on all fronts – technical, financial, and through capacity building – is essential. This requires reforms to create space for private sector investment by unbundling the distribution sector. Addressing the current governance deficit in Discoms cannot be achieved through over-legislation or centralization, but by enhancing institutional capacity, up-skilling personnel, and ensuring financial sustainability in operations.

Government and regulators must focus not only on cost reduction but also on addressing capital-intensive aspects to achieve the clean energy transition. In the face of business-as-usual practices and the rapid integration of e-mobility with the grid, Discoms and the grid may become unsustainable and collapse sooner rather than later. To ensure the survival of Discoms, the pace of distribution reforms, infusion of private investment, and the role of taxpayers will be central to the success of our clean energy transition, particularly in low-income states.