Electricity Market Design: Solutions to create an efficient, optimal and reliable market framework

As the country’s energy sector moves towards surplus capacity and the sh­a­re of renewable energy grows, th­e­re is a need to redesign the energy ma­­r­­ket to optimise power procurement costs. The majority (about 90 per cent) of the power procurement in the country is through inflexible long-duration power purchase agreements (PPAs) as well as self-scheduling, which creates system in­efficiencies and leads to suboptimal ca­pacity utilisation. To facilitate energy tra­nsition and ensure optimum capacity utilisation, deepening of the short-term power market as well as the introduction of a capacity market are imperative.

Recently, a group constituted by the Mi­nistry of Power (MoP) for “Develop­ment of Electricity Market in India” proposed comprehensive solutions to address the key issues in the country’s electricity ma­rket design, such as the dominance of inflexible long-term contracts, the la­ck of re­so­urce adequacy planning at the centre and in the states, and the high reliance on self-scheduling by states. It proposed solutions to encourage market participation for renewables, ensure a well-developed ancillary services market, and re­duce system inefficiencies through low reliance on self-scheduling. The solutions are aimed at creating an efficient, optimal and reliable market framework to enable the en­ergy transition and integration of renewable energy into the grid.

Renewable Watch examines the key issu­es and challenges outlined in the report as well as the solutions proposed for an electricity market redesign…

Need for redesigning electricity markets

The Indian electricity market is dominated by inflexible and long-duration (about 25 years) PPAs. Although market-based me­chanisms, power exchanges and bilateral trading came into existe­n­ce in 2008, these have typically reflected about 5-6 per cent of the day-ahead electricity procurement over the past five years. The discoms de­pend on self-scheduling for almost 90 per cent of their power requirements. The lack of a uniform framework/nationally coordinated approach for power procurement le­ads to suboptimal despatch, with ch­ea­per plants in the national merit order not be­ing scheduled to their full available capacity.

Although renewable energy is establishing itself as a significant source of po­wer generation, it continues to be pro­cured primarily through longer-duration and inflexible contracts. In­ter­national experience in­dicates that renewables and the associated balancing energy sources are best in­tegrated through market-linked mechani­s­ms. An increase in renewable energy in the overall energy mix will require a robust market-based platform to encourage new investments and to enable balancing of variability in the grid by harnessing the di­versity that the market offers.

India has diversity in demand patterns and resource availability. The seasonal va­riation in demand provides scope for implementing a capacity market in the co­untry, which is not supported by the current market fra­mework and operating procedures. Furth­er, although India has integrated all its regi­ons into a synchronous grid, the current wholesale po­wer market continues to operate in silos, leaving significant untapp­-ed op­p­ortu­ni­ti­es for optimisation and ac­hieving a national merit order.

Resource adequacy (RA) planning has be­en absent from the country’s electricity market operations. RA, which re­qu­ires ma­intaining sufficient reserve margins to absorb demand and supply fluctuations, has become all the more importa­nt with larger volumes of renewable en­ergy being integrated into the grid. Coordinated na­tional- and discom-level RA planning is needed to maintain optimal generation ca­pacity while minimising the costs. In­tro­ducing capacity markets and ushering in larger reforms such as market-based economic despat­ch (MBED) and contracting of renewables through the market are nee­d­ed for RA planning.  The RA as­s­essment at a disc­om level needs to take granular time blo­ck-wise probabilistic estimates of generation availability and de­s­patch to arrive at the need for additional contracts, sans which discoms are likely to either ov­er- or under-contract, leading to reliability iss-u­es or higher costs to consumers.

Roadmap for electricity market reforms

RA and capacity contracting: In order to address the concerns regarding RA planning as the Central Electricity Authority (CEA) RA framework gets rolled out in 2023, there is a need to introduce a fra­mework for capacity markets. Since the requirements of the states vary on a temporal and pan-Indian basis, standardised seasonal/monthly contracts and custom bilateral contracts could be introduced.

For the short-term capacity market, to be­gin with, the group recommends introducing a capacity market through an e-bidding portal, which would facilitate two-part tariff-based bidding (fixed char­ges and variable charges). Under this, discoms co­uld also put up their surplus capacity for sale. Subsequently, standardised ex­change-based contracts for trading of capacity, where discoms can participate as sellers of surplus capacity and buyers for deficit, could be introduced.

For a long-term capacity market, until MBED is implemented, discoms could, auction bilateral contracts of 12-15 years duration by inviting a capacity bid and an energy bid (with a bilateral contract settlement [BCS] mechanism). Mean­while, with the implementation of MBED, new bilateral auctions will have energy price discovery on the exchange, without BCS.

Enhancing the efficiency of the day-ahead market: The inflexibility aspect of self-scheduling within state control areas restricts the sharing of reserves across states as well as the ex­tent to which variable renewable ener­gy can be deployed within the state’s boundaries. Market-ba­sed scheduling and despatch will en­large the balancing area from the state’s bo­un­daries to regional/national boundaries and bring in the desired flexibility to dep­loy higher volumes of renewable energy with greater reliability.

In order to enhance the efficiency of the day-ahead market, the group recomme­nds that the Grid Controller of India sh­ould initiate security constrained economic despatch (SCED) with unit commitment (UC) on a D-1/D-3 basis for various categories of thermal stations. This could be taken up first for the thermal fleet of NTPC and then gradually ex­pan­ded to the interstate generating station (ISGS) thermal fleet. Later, the entire ISGS fleet as well as merchant capacities would be mandated to participate in the day-ahead market.

Renewable energy participation in the day-ahead market: In order to promote renewable energy participation in the day-ahead market, the group recomme­nds introducing a single strike price option for a 15-year PPA initially, to gain investor confidence and ensure bankability. Other variants co­uld be introduced subsequently. Apart from this, the group recommends that 20 per cent of the required renewable energy capacity be procured through market-based BCS mechanisms, while the re­ma­ining 80 per cent could be procured by discoms. While for established renewable energy techno­lo­gies, the BCS model with adequate fun­ding support could be adopted, for new renewable energy technologies (su­ch as offshore wind), adequate reve­nue protection is needed.

Market-based mechanism for secondary reserves: In Phase I, the group recomme­nds operationalising the Central Electri­city Regulatory Commission (CERC) an­cillary services regulation for administered procurement of secondary reser­ves. Mean­wh­ile, in Phase II, market-ba­sed procurement of secondary reser­ves could be in­troduced. In terms of the im­plementation framework, the group recommends introducing a uniform product for secondary frequency re­gulation. A participation factor, based on ra­mping capability, cost and available he­a­droom, could be consi­dered for des­pa­tching the available stack of resources. Su­ch a factor would inherently give preference to fast res­ponding so­urces since they can provide better re­gulation performance than traditional so­urces. Further, re­sources sh­ou­­ld be paid availability char­ges as they reserve some of their ca­pa­city for ancillary servi­ces instead of participating in energy mar­kets. To begin wi­th, ancillary and en­ergy can be independent markets as co-optimisation requires a single bidding fra­mework for energy and ancillary. Go­ing forward, co-optimisation of energy and ancillary services can bring optimisation in system costs.

Financial instruments for electricity markets

At present, the Indian electricity market do­es not have financial instruments th­ro­ugh which market participants can hedge against price risks. While this is largely attributable to the dominance of long-term PPAs for power procurement, as the volu­mes on the power ex­ch­anges increase, financial instrume­n­ts for electricity will be imperative. In one of its reports, the IEEFA notes that the spot mar­ket on the power exchan­ges and the derivatives market will feed into each ot­her. It will be a virtuous cy­cle wherein the derivatives market will establish forward pri­ces, more participants will shift from PPAs to exch­an­ges, thereby increa­sing liquidity in de­rivatives and subsequently increa­sing liquidity in the spot market on the po­wer exchanges and vice versa.

In order to operationalise financial ins­tr­u­ments in the electricity market, the Se­cu­rities and Exchange Board of India (SEBI) and the CERC have reached an understanding to allow futures trading in electricity. It has been agreed that the former will oversee the functioning of all financially traded electricity forwards while the latter will regulate physically settled forwa­rd/ futures whe­re electricity is delivered at a future date at the contracted price.  With regard to the future roadmap for the introduction of financial instrume­nts in the electricity market, the report on electricity market de­ve­lopment notes that there is a need for coordination between the electricity and the financial regulator to formulate market rules for the monitoring and surveillance of derivatives transactions. The financial regulator needs to assess wh­en to introduce such products. Events such as increasing liquidity and price volatility could be the signals to watch.


The MoP’s efforts to redesign the electricity market are well timed and are mu­ch ne­eded to meet the emerging re­qui­re­ments of the power sector. Once im­ple­mented, the various recommendations of the MoP group wi­ll go a long way in making the country’s energy market more dynamic in nature, wh­ile ca­talysing the en­ergy transition and optimising power procurement costs.

By Priyanka Kwatra