Demand flexibility (DF) refers to the capacity of demand-side loads to modulate consumption by reducing, increasing, or shifting them across the hours of the day in response to price signals or direct dispatch instructions triggered by certain grid conditions. Demand response (DR) is a subset of DF that refers specifically to event-triggered curtailment or load reduction programmes typically contracted and operated by an electricity utility. This brief uses DF as the encompassing term and DR when referring specifically to curtailment-based programmes.

Unlocking DF at scale requires regulations that focus on key components (Figure 1) beyond time-of-day (ToD) tariffs and utility-led DF programmes. ToD tariffs can shape everyday behaviour but do not help manage local congestion or short-duration peak loads. Utilityled programmes, including dynamic tools such as critical peak pricing or direct load control, are difficult to scale and operate across diverse locations and grid conditions. A well-designed DF market resolves both limitations by enabling aggregators to coordinate flexible load where and when the grid needs it the most, and to stack revenue across multiple streams, making participation commercially viable (Rawson 2026a, 2026b).

While the value of DF for consumers and the grid is generally recognised, much of it remains untapped. For example, the International Energy Agency (IEA) estimates that globally, with installed generation capacity of 8000 GW, less than 100 GW of DR is utilised (IEA 2025). To understand what it takes to unlock this potential in India, this roadmap draws on three approaches. The objective is to provide policymakers, regulators, and utilities with a structured approach to move past the ‘pilot paralysis’ stage in implementing DF (Singh et al. 2025).

First, sections 3, 4, and 5 review how DF has been demonstrated across consumer segments, the operational models through which it is delivered, and the revenue pathways it has access to globally. Second, section 6 presents case studies of the regulatory evolution in GB and Australia, examining the coordinated actions of system operators, economic regulators, distribution utilities, aggregators, and retailers that enabled DF markets to scale. Third, section 7 presents findings from a structured survey of 14 power distribution companies (discom) officials and five semistructured interviews, assessing India’s operational readiness for DF implementation. The section also outlines short and medium-term next steps for each pillar, based on the survey and global case studies. Section 8 details and consolidates the action points.

DF can be operationalised using multiple models, from behavioural programmes to supplier-managed automated interventions. DF interventions can be broadly categorised as shown in Figure 2. Each category offers increasing levels of control, predictability, and system value.

These are the most common operational models, but they can become valuable only when the economic pathways are defined and accessible. The next section provides an overview of the same across key global markets.

Figure 2. Demand flexibility interventions vary by the mode and intensity of consumer participation

Our review of global DF market developments suggests that even when DF’s technical potential is high, delivery at scale depends on the coordinated evolution of five pillars: (1) advanced metering infrastructure (AMI), data exchange, and consent architecture; (2) device-level visibility and flexibility readiness; (3) consumer-facing price signals; (4) market access and revenue-stacking pathways for flexibility services; and (5) evidence-based regulatory designs and institutional collaboration. This five-pillar framework that structures our analysis is detailed in Annexure 2.

The two case studies that follow illustrate how these five interdependent pillars progressively enabled market access for different DF services in GB and Australia. Both case studies demonstrate that no single reform is sufficient on its own (Figure 3). The institutional structure of the GB and Australian power markets is described in Annexure 3.

Figure 3. Scaling demand flexibility requires coordinated progress across five interdependent pillars, from metering and data infrastructure to governance

Case study 1: Great Britain’s demand flexibility road map

GB’s power system is characterised by high RE penetration (44 per cent of electricity production in 2025), winter-peaking demand, declining winter reserve margins, and increasing local grid congestion due to the rapid uptake of DERs such as rooftop solar panels, EVs, and heat pumps (NESO 2026a). Increased variability on both the supply and demand sides requires additional balancing by the NESO. Consequently, NESO’s balancing-service spending jumped from GBP 949 million in 2021–22 to GBP 2.6 billion in 2022–23, with the costs borne by consumers through higher system charges (NESO 2023a). Additionally, localised grid congestion is strengthening the case for flexibility as a least-cost alternative to infrastructure investment. Modelling studies estimate that scaling flexible demand could save between GBP 30 billion and GBP 70 billion in system costs over 2020–50 (Department for Energy Security & Net Zero [UK] (DESNZ), Ofgem, and NESO 2025). National policy frameworks prioritise enabling flexible demand to reduce system costs, support RE integration, and improve network efficiency (BEIS and Ofgem 2017, 2021; DESNZ, Ofgem, and NESO 2025).

We analyse the steps that led to the evolution of a DF market in GB, based on the five-pillar framework discussed above. Figure 4 summarises the major system gaps identified and the institutional and regulatory interventions introduced to address them.

Pillar 1: Advanced metering infrastructure, data exchange, and consent architecture

• Metering: The smart meterroll-out began in 2008 under a national government programme and with regulatory targets set for suppliers through licence conditions. It reached around 70 per cent saturation among households as of September 2025 (DESNZ 2025b). Smart meter communications are routed through a centrally managed network operated by the Data Communications Company (DCC), which ensures secure data transfer and continuity even when consumers switch suppliers (Smart DCC Limited 2025).
• National consent framework for third-party access to energy data: The 2018 Data Access and Privacy Framework established that while daily consumption data is shared with suppliers by default for billing purposes, explicit opt-in consent is required for sharing more granular data with any third-party service provider/retailer (DESNZ and BEIS 2018). As part of the Data Sharing Infrastructure Programme, Ofgem is developing a digital mechanism that will allow consumers to grant, manage, and withdraw consent across authorised energy data users in a more streamlined and interoperable manner (Ofgem 2024a).
• Framework for consumers’ access to smart meter data: Consumers can access their consumption data via a free in-home display tool or directly through a smart meter that has devices connected to it through the home area network for more real-time access (DESNZ and BEIS 2018). Real-time third-party access through consumers’ smart meters is also enabled, subject to consumer consent via the DCC network. Smart meter data has also progressively been made available in aggregated form to distribution utilities to improve LV network visibility (Ofgem 2022a). Impact assessments estimate average electricity consumption reduction of about 3 per cent among households equipped with smart meters, primarily driven by behavioural interventions facilitated by smart meter data (DESNZ 2023).

Pillar 2: Device-level visibility and flexibility readiness

• Device- and market-level interoperability: At the device level, adoption of communication standards for appliances such as heat pumps and batteries remains voluntary, though smart EV- charging regulations have mandated open protocols, such as the Open Charge Point Protocol (OCPP), for charging points (UK Parliament 2018). At the market level, flexibility procurement platforms use different application programming interfaces (APIs), data formats, and dispatch protocols, making multi-region participation prohibitively expensive for smaller providers. The Open Networks Programme identified Open Automated Demand Response (OpenADR) 3.0 as the standard dispatch API to be adopted across all GB flexibility markets (Latief 2025; Nordman et al. 2024).
• DER visibility: Ofgem is developing the Flexibility Market Asset Registration framework to create a harmonised registry for assets participating across wholesale and local flexibility markets, with implementation expected through NESO and distribution utilities (Ofgem 2025).
• Expanding the stock of DERs: Along with smart EV-charging regulations, heat pump deployment programmes combined with targeted ToU tariffs have expanded the pool of controllable electrified heating loads (DESNZ, Ofgem, and NESO 2025). Empirical evidence from over 6,500 households in GB showed that a ToU tariff designed for heat pumps halved evening peak consumption; load shifting was demonstrated to be feasible on cold days and across building types, while annual energy bill amounts reduced by 18 per cent (Bernard et al. 2024).

Pillar 3: Consumer-facing price signals

Peak and off-peak tariffs have been available to consumers in GB since the late 1970s. As the smart meter roll-out provided access to more interval data starting in 2013, retailer-specific dynamic tariffs such as Octopus Agile (Octopus Energy n.d.) emerged to enable consumers to benefit from wholesale price fluctuations. The Market-wide Half-Hourly Settlement (Ofgem 2021) proposes to further enable this by aligning supplier costs with actual half-hourly consumption, creating a strong incentive to offer ToU tariffs. Personalised tariffs based on consumption patterns also increase the value of flexible technologies for consumers.

Pillar 4: Market access and revenue stacking pathways for flexibility services

• Granular price signals for flexibility in wholesale markets: Reforms improved real-time imbalance prices so that system stress and the cost of load shedding are reflected in the prices paid by market participants when they deviate from the schedule. This increases the value of flexible demand that can quickly reduce or shift load during tight system situations (Ofgem 2014). It served as a necessary upstream condition for retail ToU tariffs to become more cost-reflective over time.
• Regulatory support for flexibility: RIIO is the regulatory framework for setting the revenues that distribution utilities are allowed to earn over a multi-year period. RIIO-ED1 (2015–23) introduced a Totex (or total expenditure) model that treats capital and operating expenditures equivalently, removing the bias towards capital investment and enabling lower-cost non-wire alternatives to compete with network expansion (Girouard 2019). This is reinforced under RIIO-ED2 (2023– 28) by a performance incentive that adjusts the utility’s return on equity up or down based on how well it develops and operates flexibility markets (Ofgem 2022b). Complementing this, the 2020 regulations require utilities to regularly report how they procure flexibility and compare its costs and benefits with those of conventional network upgrades (Ofgem 2024b).
• Market access for DF across multiple value streams: The capacity market made demand-side resources eligible for forward capacity (2014), while the parallel access to balancing services (2020), bespoke services such as the DFS (2022), and distribution flexibility markets enabled participation across multiple value streams (Department of Energy & Climate Change [UK] [DECC] 2013; Elexon Limited n.d.). For example, local flexibility markets allow aggregated DERs above a defined capacity to earn payments for DF at congested network locations. However, coordination of products and settlement rules for efficient revenue stacking are an ongoing challenge (Blake and Brooks 2023).
• Operational coordination across markets: In the UK, this was enabled through standardisation under the Open Networks programme, which addressed the fragmentation where multiple, inconsistent contract and participation requirements acted as a barrier to scale. This included common definitions of flexibility products (defined by response time, duration, and firmness of commitment), a common asset prequalification questionnaire, contract frameworks, and standard methodologies for comparing flexibility with network reinforcement (Energy Networks Association [ENA], n.d.).

Pillar 5: Evidence-based regulatory designs and institutional collaboration

• Pilot-to-programmes framework: Innovation allowance and competitive funding under RIIO can support trials of DR and other smart grid projects (Ofgem 2015, 2026). Further, the Open Networks programme institutionalised the following approach: Funded trials were undertaken by distribution utilities; the results were transparently reported and reviewed by industry working groups, and then translated into common standards and tools before being adopted across all networks as business-as-usual (ENA and Ofgem 2021).
• From successful pilots to programmes: The DFS began as a trial in the winter of 2022–23 to test large-scale behavioural DR, initially operating as a day-ahead contingency service that guaranteed registered participants a maximum of 12 test dispatch triggers. To build provider confidence and maximise early participation, the pilot’s design explicitly avoided performance penalties for under-delivery and offered registered participants a highly lucrative, guaranteed acceptance price of GBP 3,000 per megawatthour (MWh) over a defined number of day-ahead dispatch triggers (NESO 2023b). As the service evolved into a regular, all-year-round, merit-based balancing tool, NESO introduced enhanced API capabilities for automated bidding and data sharing, which reduced operational friction and made it easier for aggregators to scale. In the 2024–25 winter season, the service reached nearly 2 million registered households and businesses, shifting ~5.4 GWh of demand during peak periods (NESO 2025).

Figure 4. Demand flexibility in GB evolved through coordinated market reforms, regulatory incentives with a strong emphasis on cost-effectiveness, and revenue-stacking pathways (2014–30)

Case study 2: Australia’s demand flexibility road map

With rooftop solar units generating over 25 per cent of its energy, Australia has the highest per-capita rooftop solar penetration globally (AEMO 2026). This has resulted in frequent midday demand troughs, steep evening ramps, and rising wholesale price volatility (Australian Energy Regulator [AER] 2025). Further, the lack of visibility of virtual power plant operations leads to increased errors in demand forecasting, exacerbating the procurement costs of frequency control ancillary services (Australian Energy Market Commission [AEMC] 2024b; AEMO 2023b). At the same time, the high wholesale price spreads and growing DER ownership present an increasingly convincing case for the economic viability of flexible resources. Fully orchestrated flexibility from gridconnected DERs could generate system-wide savings of AUD 14 billion annually by 2050, primarily through avoided investments in generation, storage, and networks (Energeia 2025). Therefore, the primary goal of the government is to convert the growing DERs into coordinated and dispatchable portfolios that behave like virtual power plants (DCCEEW 2024).

Figure 5 summarises the major system gaps identified and the institutional and regulatory interventions introduced to address them.

Pillar 1: Advanced metering infrastructure, data exchange, and consent architecture

• Metering: Australia initially followed a marketled roll-out in states apart from Victoria, which mandated advanced meters from 2009 onwards. In 2024, the Australian government authorized an accelerated roll-out, setting a target of universal smart meter coverage by 2030. The distribution network service provider (DNSP) is required to schedule a date and get regulatory approval for retiring clusters of legacy meters, and the retailer has to replace them with smart meters, coordinating with the metering service provider. Current penetration is over 55 per cent nationally, with higher penetration in Victoria (AEMC 2023; AEMO 2021).
• National consent framework for third-party access to energy data: The Consumer Data Right legal framework provides a standardised consentbased mechanism for consumers to share their energy data with accredited third-party service providers. The retailers and the market operator are the primary and secondary data holders who must authenticate the consumer’s consent and facilitate the transfer of the requested data to the third party (AEMO n.d.-a). The standardised consent architecture ensures that third-party aggregators can access consumer energy data without the need for bespoke bilateral agreements with each retailer.
• Framework for consumers’ access to smart meter data: Minimum data provision requirements mandate that retailers and DNSPs provide consumers with up to 24 months of validated interval data in standardised formats, ensuring nationally consistent data delivery (AEMO 2021). However, access remains requestbased and retailer-mediated rather than realtime or API-enabled. From November 2028, new smart meters must provide free access to real-time meter data via the home area network to consumers and authorised third parties, using the interoperability and security standards set by the market operator (AEMC 2025). The rules also enhance DNSPs’ access to data on power quality, as measured at the consumer-end meter, to improve LV network visibility and support consumer energy resource integration (AEMC 2024a).

Pillar 2: Device-level visibility and flexibility readiness

• Communication interoperability: Through the Distributed Energy Integration Program (DEIP), cross-sector technical working groups have developed nationally aligned standards for smart inverters and batteries (DEIP Interoperability Steering Committee 2023). The standards specify remote control capabilities and emergency grid support functions to enable secure integration with distribution networks (DEIP Interoperability Steering Committee 2023). Further, dynamic operating envelopes allow DNSPs to adjust DER export limits based on real-time network capacity using standardised control frameworks, thereby enabling active management of rooftop solar panels and batteries on LV networks (AER 2023).
• DER visibility: The market operator manages the DER Register and the Distributed Service Provider Information Portal, which provides system-wide visibility of rooftop solar units, batteries, and the participation of demand-side resources. These tools support forecasting, reliability modelling, dynamic operating envelopes, and improved LV network management (AEMO 2023a).
• Expanding the stock of DERs: Federal support for small-scale behind-the-meter batteries to complement new and existing roof-top solar installations expanded the pool of dispatchable distributed storage for future DR programmes (DCCEEW 2025).

Pillar 3: Consumer-facing price signals

Retail tariff reforms under the ‘power of choice’ programme supported the implementation of costreflective ToU and demand-based network tariffs to reflect peak network costs and encourage consumers to shift consumption away from congested periods (AEMC 2012). Several Australian retailers have introduced ‘solar sponge’ tariffs, which offer very low or zero import prices during periods of high solar generation, directly incentivising households to shift flexible loads such as EV charging, hot water systems, and pool pumps to these periods (AEMC 2021). The Australian government is also introducing the Solar Sharer Offer from July 2026, a new electricity pricing plan that will give all households access to free daytime power during peak solar generation, thereby helping to lower bills and make optimal use of Australia’s excess solar energy (DCCEEW 2025). Collectively, this constitutes the consumer-facing price signal layer in Australia’s DF architecture.

Pillar 4: Market access and revenuestacking pathways for flexibility services

• Granular price signal for flexibility in wholesale markets: The wholesale power market was previously dispatched at 5-minute intervals, but settlement occurred at the 30-minute average price, which undervalued flexibility. The FiveMinute Settlement reform aligned dispatch and settlement intervals and sharpened the price signals, rewarding fast-response assets such as batteries and exposing wholesale market participants to more granular costs and revenues (AEMO 2017).
• Regulatory support for flexibility: Distribution regulatory reforms introduced performancebased incentives on utilities for investing in nonwire alternatives rather than network expansion (AER 2021a).
• Market access for DF across multiple value streams: The wholesale DR mechanism allowed aggregators to bid and dispatch through the same National Electricity Market (Australia) (NEM) market bidding process used by supplyside resources. Participation requires metered loads with at least 1 MW of dispatchable capacity and a proposed baseline method that meets the standards defined for accuracy and bias. This opened a clear pathway for implementation and embedded DF (only load curtailment) within core market operations rather than treating it as a separate programme (AER 2021b). Further reforms by the regulator also provided a technical framework to allow device-level metering and settlement and unlock granular monetisation of DERs (AEMC 2024c).

Pillar 5: Evidence-based regulatory designs and institutional collaboration

• Pilot-to-programmes framework: The Australian Renewable Energy Agency (ARENA) is a nonrule-making body that invests in proof-of-concept projects of technologies that are not yet costcompetitive but can deliver system-wide value and generate the operational evidence used to inform regulatory reform from multi-year regulatory sandboxes.
• From successful pilots to large-scale programmes: The ARENA-funded short-notice RERT10 proof-of-concept trial (2019–22) outperformed the 200-MW target in two out of three years, leading to the incorporation of DR into NEM’s reliability framework. It succeeded by standardising baselines, running strict performance tests before each season (summer/winter), and diversifying across residential, smallbusiness, and large C&I customers, thus reducing delivery risk and generating insights from diverse segments. Run entirely through AEMO’s existing RERT framework, it gave the market operator full visibility of the participating DF resources, integrating them with existing market mechanisms and helping shape subsequent reforms and DR programmes (AEMO n.d.-b; Briggs et al. 2023).

Figure 5. Demand flexibility reforms in Australia were sequenced through iterative market rules, changes in technical codes, and proof-of-concept demonstrations (2017–25)

As these case studies show, a pathway or single destination when developing a DF market. Different systems, through incremental reforms, can make progress towards better integration of demand-side resources. Critically, GB’s case study demonstrates that early utility-led programmes and pilots play a foundational role, but scale is achieved only when flexibility is standardised, monetised across multiple value streams, and incorporated into core market operations.

The next section discusses the status of each pillar of market creation in India, the remaining gaps, and the steps needed to fill them in the short and medium term.

The following section details the action points introduced in Section 7, organised under the same five-pillar framework. The recommendations are not sufficient in isolation. Earlier actions create the foundations that later interventions depend on. For example, metering infrastructure enables tariff reform, tariff signals expand the flexible asset stock, and market access mechanisms determine whether aggregators can monetise that stock at scale. The steps are for short-term priority (0-3 years), unless otherwise noted.

Pillar 1: Advanced metering infrastructure, data exchange, and consent architecture

• Establish minimum standards for smart meter data recording schemas under RDSS. Even where interval data exists, the non-standardised structure, missing data, incomplete or inconsistent metadata tagging, and lack of access protocols raise integration costs and block interoperability (DESNZ 2025a). The issue is exacerbated in India, as multiple service providers are responsible for installing smart meters and setting up the related infrastructure in each discom under the RDSS (REC, PFC, and MoP 2021). Standardised data schemas would allow third parties to consistently interpret, access, and integrate smart meter data across discoms.
• Define regulatory standards for a synthetic smart meter data repository to support estimation of DF potential while the AMI rollout matures. Synthetic datasets can replicate consumers’ energy consumption patterns without exposing their actual profiles. This enables flexibility assessment, tariff response simulation, and DR modelling while the physical AMI roll-out and data-sharing infrastructure mature (CNZ 2025). Establishing minimum quality standards for synthetic data will allow this analytical work to proceed in parallel with infrastructure deployment. This approach will limit the exposure of actual data to only those entities responsible for synthetic data generation, thus preserving consumer privacy while enabling broader innovation.
• Develop a digital, secure, API-based consumer consent architecture for smart meter data sharing between discoms and authorised flexibility service providers (across short and medium term). In the absence of a standardised consent architecture, aggregators need to negotiate bilateral agreements with utilities to obtain access to smart meter data, which limits the scalability of their products. India’s Digital Personal Data Protection Act (2023) establishes the right of individuals to control how their personal data is collected, used, and shared, but it does not operationalise a sector-specific consent architecture for electricity markets. Similarly, RDSS focuses on meter deployment and infrastructure interoperability but not on consumer data governance or third-party sharing (REC, PFC, and MoP 2021). A digital consent framework integrated with smart meter apps – similar to GB’s consumer consent service – would streamline consumer recruitment for DF programmes. Standards defined in the short term can then be mandated for all third-party data sharing in the medium term.

Pillar 2: Device-level visibility and flexibility readiness

• Introduce a voluntary DR-ready designation within the Bureau of Energy Efficiency (BEE) S&L Program. The BEE’s S&L Program sets minimum energy performance standards and provides bvisibility into efficient appliance stock and market penetration trends (Vasudha Foundation and BEE 2024). However, these frameworks do not define, tag, or track ‘DRcapable’ devices. After nearly two decades of implementing the S&L Program, a ready institutional pathway is emerging for BEE to introduce a DR readiness designation and extend visibility into the share of appliances that are technically capable of responding to a DR event remotely. This will enable credible potential assessment, certification, and market integration of automation-ready appliances.
• Define voluntary, automation-ready pathways in building codes to operationalise peak reduction targets. The Energy Conservation and Sustainable Building Code sets enhanced efficiency standards for commercial buildings and includes a ‘Grid Harmonisation’ category with peak load reduction targets of 5, 7.5, and 10 per cent (BEE 2024). However, it does not specify the technical pathways for grid integration, nor does it prescribe the minimum automation, interoperability, or communication requirements to achieve these goals. Defining these technical conditions would help convert peak reduction targets from aspirational benchmarks to operationalised demand-side resources.
• Commission commercial end-use surveys for key building categories to map flexibility potential by building type and climate zone. BEE’s building energy surveys can be extended from whole-building energy performance benchmarking to capture end-use types, equipment inventories, occupancy characteristics, and hourly load profiles obtained from metering across climate zones and building types. It can draw on models such as the California CEUS (CEC 2024), which served as the foundational input to the state’s DR Potential Study (Gerke et al. 2024). Commissioning equivalent surveys in India would enable empirical estimation of flexibility potential, prioritisation of high-value end uses, and more targeted DF programme designs.
• Establish nationally recognised communication and interoperability standards for grid-edge devices, with formal BIS recognition and alignment with IES. Where smart meters are not yet installed, asset-level devices such as smart plugs can enable measurement and verification. In India, DF pilots have used such grid-edge devices and related protocols for communication (Poojary et al. 2015; Singh et al. 2025). While EV-charging infrastructure guidelines already promote open communication protocols such as OCPP and UEI to ensure interoperability (MoP 2024), similar nationally recognised standards do not yet exist for other flexible loads. Our interviews indicate that the industry communication standards used in pilots lack formal recognition, unlike the Bureau of Indian Standards (BIS) and Central Electricity Authority (CEA)-approved standards for other power system equipment (CEA 2019, 2020). The IES initiative’s core infrastructure layer, which is designed to support standardised protocols and technology-agnostic data architecture across utilities, provides an institutional grounding for this standardisation process and would ensure that device-level standards are compatible with the broader digital infrastructure being developed nationally. It must be complemented by formal recognition by the BIS or CEA to give discoms the regulatory basis to accept these standards in official measurement and settlement processes.
• Require discoms to publish LV network monitoring data under the RDSS, specifying the roll-out of DT-level interval metering and its integration with distribution management systems. India has made a foundational investment through the RDSS, which has sanctioned communicable smart DT meters for approximately 5.4 million DTs nationally – though only 3 per cent have smart meters in communicating mode as of 2024 (Kulkarni et al. 2025). Existing DT meters are primarily used for AT&C loss calculation rather than real-time load monitoring, and their data is not integrated with discoms’ operational systems at an interval resolution. Emerging digital twin initiatives across Indian discoms, such as Gujarat’s Urja Sanvardhanam platform (Times News Network 2025), indicate a growing shift towards integrating feeder- and DT-level data to improve real-time monitoring, forecasting, and networkplanning workflows. The REC and PFC should include LV monitoring plans as a milestone under the RDSS, prioritising DTs in high–DER penetration areas and constrained urban feeders where local flexibility needs are likely to emerge first.
• Establish minimum interoperable standards for grid communication with DERs aligned with the IES (Medium term). The short-term actions above establish formal recognition for device-level communication standards and expand LV network monitoring. Building on this, medium-term standardisation should extend interoperability requirements to the full range of DERs such as, rooftop solar inverters, grid-connected batteries, and smart appliances, ensuring that device-level communication protocols are compatible with the IES data architecture. This would create a unified technical layer across which aggregators, discoms, and system operators can coordinate dispatch and settlement.
• Commission national DF potential studies using appliance penetration data and smart meter datasets (Medium term). As smart meter coverage matures and the DR-ready appliance designation proposed above is introduced, the data conditions for robust national potential studies will improve. Commissioning these studies would produce empirically grounded estimates of flexibility potential by consumer segment, geography, and load type. These estimates would directly inform the state electricity regulatory reviews of Demand Flexibility Portfolio Obligations (DFPO) trajectories and cost-effectiveness thresholds.

Pillar 3: Consumer-facing price signals

• Use smart meter interval data to evaluate ToD tariff impact by consumer segment. India’s ToD tariffs for C&I consumers have established a foundation of time-varying pricing and early behavioural flexibility signals (Malhotra et al. 2024). However, price differentials remain modest, are not regularly updated, and are weakly aligned with wholesale or network conditions. Consequently, although discoms identify flexibility potential in residential ACs and behind-the-meter storage (Figure 8), consumers have limited incentive to automate or enrol these assets in flexibility programmes. Regulators and discoms should use smart meter data to assess how ToU tariffs affect different consumer groups and identify who responds to price signals to inform innovative tariff designs and DF potential assessment studies.
• Evaluate how tariff structures impact DER adoption and the flexible asset stock. Tariff design influences not only consumer behaviour but also the investment decision to install DERs. Regulators should direct discoms to report how ToD differentials, export tariffs, and net metering13 design affect the payback period and the adoption of rooftop solar panels, batteries, and smart appliances, since these assets form the underlying stock from which future flexibility markets can draw.
• Introduce critical peak pricing for large C&I consumers based on To Devaluation evidence (Medium term). As smart meter data matures and ToD impact assessments are completed, SERCs can use this evidence base to design and pilot CPP for large C&I consumers, where load density and energy management systems make response most reliable.

Pillar 4: Market access and revenuestacking pathways for flexibility services

• Extend the DF obligations framework to more states, ensuring the penalty design serves as a strong market signal beyond compliance formalities. To make flexibility services economically viable and scalable, regulatory mandates similar to MERC’s DFPOs must be extended to other states grappling with high RE and rapid DER penetration, distribution network congestion, and urban peak stress. Under India’s current cost-plus regulatory framework, discoms earn regulated returns on capital investments, which can weaken the incentive to pursue DR as an alternative to network expansion (Malhotra et al. 2024). To address this, SERCs must align DFPO penalties with the returns from network investments so that non-compliance carries a comparable financial impact in the short and long terms.
• Establish a central registry of qualified aggregators and a national pre-qualification framework to reduce barriers to multimarket entry. Current regulations define aggregators as entities registered with the distribution licensee rather than independently recognised market participants (MERC 2024). SERCs should establish central aggregator registration at the SERC level, with pre-defined telemetry, measurement accuracy standards, and verification protocols for different DF service types. Discoms would retain their procurement and contracting role while allowing qualified aggregators to approach any discom within their state and participate in national ancillary services. The CEA and the Forum of Regulators should develop a standardised national eligibility framework to define common technical and commercial criteria, thereby reducing the administrative burden of multi-market entry and enabling aggregators to build scale across states.
• Develop a common evaluation methodology, under a national working group, for comparing flexibility savings with network investment (Medium term). Extending DF obligations and aggregator registration creates procurement activity, but without a common methodology, discoms face inconsistent incentives and regulators lack tools to assess cost-effectiveness. A national working group under MoP or All India Discoms’ Association (AIDA) should develop a standard framework covering baseline assumptions, avoided cost calculations, and reporting norms.
• Under DF regulations, mandate discoms to assess non-wire alternatives for Capex projects above a defined threshold, using a common evaluation methodology across states (Medium term). This builds directly on the methodology above, giving SERCs a consistent basis for approving network investment decisions.
• Develop standard bidding templates for DF procurement with defined baselines and MVS requirements and mandate discoms to operationalise these through IES core data infrastructure and open APIs (Medium term). This ensures procurement is interoperable and scalable across states.
• Leverage emerging smart metering and data infrastructure to link discoms’ regulated returns to service quality and flexibility delivery (Medium term). More than half the discoms do not publish any regular or consistent outage data (Borah and Sane 2025), and even where reliability indices are reported, there are no mechanisms that automatically link service quality performance to financial consequences for discoms (Mandal et al. 2019). This means service quality rules for discoms are weakly enforced in practice. Regulators could remedy this by linking a portion of regulated discom returns to measurable performance on flexibility procurement and supply reliability. A key constraint today is the lack of real-time data at the feeder and transformer levels, which makes performance difficult to verify. However, the ongoing smart meter roll-out under RDSS and progress with the National Feeder Monitoring System (MoP 2026) will progressively enable this, allowing regulators to tie a portion of discom returns to measurable improvements in flexibility delivery and supply reliability.

Pillar 5: Evidence-based regulatory designs and institutional collaboration

• Create funding mechanisms at the national and state levels for cross-state, large-scale DF innovation and technology demonstrations. While there are avenues to fund early-stage risk in innovation in generation and transmission (CERC 2026), there is a dearth of funding at the distribution level. We recommend that the Ministry of Power (MoP) consider establishing a competitive, grant-based national demonstration fund for multi-party, multi-state DF programmes, covering automation-assisted DR, DR aggregation, and storage-as-a-service, with mandatory obligations on transparent reporting, rigorous evidence collection, and alignment with national policy initiatives, including the IES and smart metering roll-out. This would support longduration demonstrations and technology testing, which is key to generating robust evidence for improved programme design. At the state level, we recommend that states establish DF innovation and research funding mechanisms aligned with Maharashtra’s Renewable Energy and Energy Storage Policy 2025–36, which explicitly mentions DR as one of its R&D focus areas (Industries, Energy, Labour, and Mining Department 2026).
• Establish a cross-state working group to standardise flexibility procurement frameworks14 and integrate demonstration findings into the state electricity regulators’ reviews of DFPO trajectories and costeffectiveness thresholds (Medium term). India’s constraint is no longer insufficient demonstrations but the lack of institutional capacity to make their findings comparable across states, cumulative, and regulatory-actionable. We recommend establishing a cross-state technical working group, convened under the MoP or a body such as AIDA, with participation by SERCs, discoms, and independent researchers. The key purpose will be to develop and iteratively refine a harmonised framework covering standard baseline methodologies by load type, replicable sandbox governance and bidding templates, minimum reporting norms for publicly funded demonstrations, and a formal channel for findings to inform SERC and CERC review of DFPO trajectories, product definitions, a cost-effective technology stack, and innovative incentive programmes for consumer enrolment. This will complement the technical interoperability design proposed under the IES.