CERC Releases Staff Paper on Capacity Market for Electricity in India

The Central Electricity Regulatory Commission has released a staff paper on 'Capacity Market for Electricity in India', proposing a comprehensive market-based framework for capacity procurement in the country’s power sector to ensure long-term resource adequacy, improve reserve availability, and strengthen grid reliability amid rising renewable energy integration and growing electricity demand.

In a detailed staff paper, the Commission stated that while India’s existing long-term Power Purchase Agreements (PPAs) already function as implicit capacity contracts by guaranteeing recovery of fixed costs based on plant availability, the country may now require a more market-linked framework where capacity contracting, dispatch, and energy pricing are increasingly indexed to competitive electricity markets. The paper clarified that the views expressed are those of the Commission and are intended to initiate stakeholder discussions rather than represent the official position of the Commission.

The paper noted that internationally, capacity markets have evolved as mechanisms operating alongside conventional energy markets to ensure sufficient generation resources remain available during periods of system stress. Such mechanisms are designed to address issues including inadequate investment signals in energy-only markets, the 'missing money' problem arising from insufficient recovery of fixed costs, poor ancillary service market design, and the operational challenges associated with intermittent renewable energy generation.

Referring to international experience, the paper discussed models adopted in Germany, United Kingdom and the United States. Germany was cited as following a strategic reserve mechanism where reserve capacities remain outside the energy market and are activated only under extreme grid stress conditions at the direction of transmission system operators. Great Britain’s centralized capacity market model, introduced through auctions beginning in 2014, was highlighted for procuring future capacity through four-year-ahead and one-year-ahead auctions based on demand curves linked to the net cost of new entry, or Net-CONE. The paper also referred to the Reliability Pricing Model operated by PJM, where capacity resources are procured through three-year forward auctions to maintain reliability standards, while California’s resource adequacy framework was cited as an example of decentralized procurement by load-serving entities.

Drawing from these international models, the paper observed that capacity remuneration in many jurisdictions is generally linked to Net-CONE, which represents the cost of new generation entry adjusted for expected revenues from energy markets. It further noted that unlike India’s current PPA framework, most global capacity markets do not guarantee full recovery of capacity charges and instead rely on robust energy markets and strict reliability obligations to provide investment certainty.

Against this backdrop, the staff paper proposed three possible alternatives for implementing a Resource Adequacy-linked capacity market in India. Under the first option, discoms would procure generation capacity through auctions based solely on capacity charges. The paper proposed that demand curves may be drawn using the Net-CONE principle, while generators’ bids for capacity remuneration would be arranged in ascending order to determine the market-clearing price. The contracts could extend up to 15 years, during which discoms would pay the discovered capacity remuneration. Simultaneously, both generators and discoms would participate independently in the day-ahead and real-time electricity markets for energy transactions. To ensure discoms retain access to contracted capacity, the paper proposed allowing buyers’ demand curves to be placed slightly above the market price cap, although it acknowledged this approach could potentially inflate market-clearing prices. The paper suggested that this mechanism could nevertheless address concerns around free-riding until all discoms fully comply with resource adequacy requirements.

The first option also proposed mandatory participation by capacity providers during peak or stress hours notified by the National Load Despatch Centre. Generators would be required to bid as price takers during such periods, and failure to clear the market could attract penalties equivalent to 1.5 times the discovered capacity charge. The paper further recommended a technology-agnostic framework that would eventually allow renewable energy projects backed by Energy Storage Systems (ESS) to participate directly in capacity markets.

The second option proposed in the paper retains the present two-part tariff structure involving capacity and variable charges but modifies dispatch arrangements. Under this design, discoms would retain scheduling rights over contracted capacity until closure of the day-ahead market window, while actual dispatch would take place through market mechanisms. Both generators and buyers would submit bids into the market, with buyers’ bids for contracted capacity positioned above the price cap to guarantee energy access. Once the market clears, the market-clearing price would be settled through the exchange while bilateral settlements between the generator and discom would account for differences between the contracted tariff and market-clearing price. The paper stated that this mechanism could simultaneously ensure efficient dispatch, adequate market liquidity, and supply security for discoms.

The third proposal involves creation of a centralised “Residual RA Obligation Capacity Market” under which a central agency designated by the Ministry of Power would procure capacity on behalf of discoms facing resource adequacy shortfalls. The proposed centralized auctions would also follow the Net-CONE principle, with bidding based solely on capacity charges. Discoms participating in the mechanism would enter into contracts with the central agency and pay proportional capacity charges discovered through auctions, while the agency would contract with successful generators. The paper suggested contract periods ranging from 10 to 15 years and proposed that shorter-term resource adequacy gaps of one to three years could be met through a separate secondary capacity market. Similar to the earlier models, generators would be required to participate during stress periods and could face penalties of 1.5 times the discovered capacity charge for non-compliance.

In addition to long-term resource adequacy mechanisms, the paper proposed a dedicated Reserve Capacity Market to address growing concerns around insufficient reserve availability and grid security. The paper observed that while reserve procurement in many global markets occurs close to real-time delivery, India currently faces inadequate reserve levels due to incomplete implementation of resource adequacy frameworks and insufficient contracted resources among discoms. The situation becomes particularly severe during solar hours when thermal plants operate near minimum technical load levels, leaving limited reserve margins available to system operators.

The paper referred to provisions under the Indian Electricity Grid Code (IEGC), 2023, which require states to maintain secondary and tertiary reserves and authorize the NLDC to procure reserves on behalf of states failing to maintain adequate reserve levels. It also highlighted provisions under the Deviation Settlement Mechanism Regulations, 2024, allowing reserve procurement costs to be recovered from deficient entities. The staff paper noted that the Ministry of Power had already facilitated procurement of 1,744 MW of gas-based generation capacity during the 2025 high-demand season between March and October, with associated costs of Rs. 2,208 crore recovered through the DSM and Ancillary Services pool accounts.

To address reserve shortages during the transition period until resource adequacy frameworks are fully implemented, the paper proposed annual reserve auctions for secondary and tertiary reserves. The proposed auction framework would allow eligible resources under the CERC Ancillary Services Regulations to participate in one-year contracts, with capacity prices determined through pay-as-cleared auctions using downward-sloping demand curves linked to Net-CONE plus 10 percent. Under the proposed mechanism, the NLDC would receive first rights over scheduling and dispatch of contracted reserve capacity. Capacity providers would retain the option to participate in Secondary Reserve Ancillary Services (SRAS), Tertiary Reserve Ancillary Services (TRAS), or energy markets depending on whether reserves are requisitioned. The paper also proposed compensation structures for different dispatch scenarios, including payments for scheduled and dispatched reserves, scheduled but undispatched reserves, and reserve capacities not requisitioned by the NLDC. Failure to meet reserve obligations could attract penalties equivalent to 1.5 times the discovered capacity charge plus ancillary service prices.

The staff paper further proposed the creation of a secondary short-term capacity market to facilitate trading of existing contracted capacities and supplement India’s existing energy-only markets. The paper noted that despite periods of high demand and elevated market prices, significant capacity can remain unavailable in the market due to silo-based contracting arrangements. To address this issue, the proposed market platform would allow capacity holders to trade capacity separately from energy for durations ranging from one to three months.

Under the first option for the short-term market, auctions would be conducted every three months for contracts covering one-month and three-month durations. The auctions would be based on double-sided bidding involving only capacity charges. Eligible sellers would include discoms with surplus contracted capacity, generating companies with spare capacity, and traders, while buyers could include deficit discoms and capacity-obligated suppliers. Similar to the long-term RA market design, both buyers and sellers would participate in day-ahead markets for actual energy dispatch, while buyers’ demand curves could be placed above the price cap to guarantee access to contracted capacity.

The second option for the short-term market proposed two-part bidding involving both capacity and energy charges. Buyers would retain scheduling rights until closure of the day-ahead market, after which generators could sell energy into the market if capacity remains unscheduled. Capacity providers participating in the energy market would again be required to clear during notified stress periods, failing which penalties amounting to 1.5 times the discovered total cost could be imposed.

The Commission has invited comments from stakeholders on the proposed frameworks covering resource adequacy-linked capacity markets, reserve capacity markets, and short-term secondary capacity markets. The proposals are expected to significantly influence future discussions around electricity market reforms in India as the country seeks to balance reliability, flexibility, and large-scale renewable energy integration within its evolving power system.