India’s commercial and industrial (C&I) sector is at an inflection point in its relationship with renewable energy (RE). What began as a cost-arbitrage play in this sector–procuring solar or wind power because it was cheaper than grid supply–is rapidly becoming a strategic necessity, driven by environmental, social, and governance (ESG) mandates, carbon border levies, investor scrutiny, and supply-chain pressures from global buyers.

Consumers in the C&I sector directly contracted over 36 GW of renewable capacity by December 2025, with solar open access (OA) accounting for the bulk at over 30 GW (Climate Group RE100 2023; Mercom India 2025). Solar OA additions reached 7.8 GW in CY2025 alone, nearly double the 3.9 GW added in CY2023 (Kothamasu 2025; Mercom India 2025). The OA market remains heavily concentrated: Karnataka, Maharashtra, and Rajasthan together account for over 60 per cent of new solar OA installations in CY2025 (Mercom India 2025), while most states see negligible activity. An additional 45 GW of solar OA projects are in various stages of development as of the end of 2025, and the pace is accelerating (Mercom India 2025). India’s C&I segment accounts for nearly half of the country’s total power demand (MoSPI 2025). How this segment procures energy over the next decade will determine whether India’s industrial economy decarbonises at the pace its climate commitments demand.

Open access has been the primary instrument enabling this shift (see Figure 1). By allowing C&I consumers to buy power directly from RE generators, OA has created a market-led pathway for decarbonisation. For consumers, it enables ESG compliance, hedges against rising grid tariffs, and supports long-term energy planning. For RE developers, it provides a bankable demand base that attracts private investment and drives competition.

Yet RE meets only ~23 per cent1 of C&I electricity demand today, through a combination of discom supply and direct OA procurement, far short of what the sector must deliver for India to meet its decarbonisation commitments. This gap is not due to a lack of demand or supply; rather, it reflects the limitations of a regulatory framework that has not kept pace with the evolving economics and requirements of corporate clean energy procurement (see Figure 2). Developers and consumers of RE report facing high and unpredictable surcharges, restrictive banking and standby rules, and prolonged administrative delays. These frictions weaken price signals and undermine the competitiveness of clean power (Sethi et al. 2020).

When C&I consumers migrate to OA, discoms face legitimate financial pressures. They lose their highest-paying customers–the same consumers who cross-subsidise agricultural and domestic tariffs. The migration triggers a cascade of under-recovery risks, including fixed-cost liabilities from power purchase agreements (PPAs), stranded network investments, additional costs for grid balancing, and increased administrative burdens (MoP 2017). India’s regulatory architecture addresses these pressures through a set of compensatory charges: CSS, AS, standby charges, banking charges, POC, and wheeling charges (see Figure 3).

In principle, each OA charge has a clear rationale. However, in practice, all six charges are affected by a common set of problems, including methodologies that are not cost-reflective, data systems that are too weak to support rigorous computation, and inconsistent application across states. The result is a framework that simultaneously undercompensates discoms and overcharges consumers. This misalignment is more urgent now than it was five years ago, as the nature of corporate clean energy demand is changing. A combination of ESG disclosure requirements, the EU’s CBAM, granular greenhouse gas (GHG) accounting standards, and supply-chain mandates from global buyers is pushing Indian companies towards a higher share of clean energy procurement. Leading C&I consumers are now contracting firm, round-the-clock (RTC) power with delivery measured in 15-minute time blocks. Procurement at scale will remain constrained if the regulatory framework governing OA remains unpredictable, litigation-prone, and economically distorting for both discoms and consumers.

Several reforms are already underway. The GEOA Rules 2022 standardised banking provisions, streamlined approval process, and lowered the OA eligibility threshold to 100 kW. The Electricity Amendment Rules, 2024, introduced sunset provisions for an additional surcharge. The draft Electricity (Amendment) Bill, 2025, proposes to phase out cross-subsidy for manufacturing, metro rail, and Indian railways, and to exempt discoms from supply obligations for consumers above 1 MW (Ministry of Power 2025a). Radical proposals, such as reclassifying all HTconnected users as OA consumers, signal meaningful shifts (Prayas Energy Group 2025). However, these reforms will take years to design, enact, and implement. The charges that currently govern OA will shape investment decisions, procurement structures, and discom finances long before any of these proposals take full effect.

Chapter 3 examines each OA charge through a consistent analytical lens–its purpose and legal basis, the drivers for reform, and the specific actions required by regulators, discoms, and policymakers to correct the current misalignment. Chapter 4 situates this regulatory analysis within the broader shift in corporate clean energy strategy, demonstrating why reforming OA charges is not merely a technical regulatory matter but a prerequisite for India’s next phase of industrial decarbonisation. The report’s recommendations are directed at specific actors– the Ministry of Power (MoP), state electricity regulatory commissions (SERCs), the Forum of Regulators (FoR), state load dispatch centres (SLDCs), discoms, and C&I consumers–with clear timeframes and expected outcomes.

India has the RE potential, policy architecture, and corporate demand to build a deep and reliable market for industrial clean energy. What it currently lacks is a robust, cost-reflective regulatory framework for OA that is methodologically transparent and consistent across jurisdictions. This report maps the path from where the framework is to where it needs to be.

Open access has emerged as a key pathway for C&I consumers to transition to RE. The pace of RE uptake, however, depends not only on enabling OA provisions but also on how various OA charges are structured and applied. These charges include the CSS, AS, standby charges, banking charges, wheeling charges, and POCs. Each charge serves a distinct purpose, ranging from compensating discoms for revenue loss to payment against services such as wheeling of power, banking, and standby power.

This chapter examines each of these OA charges through a common analytical lens. First, we analyse their purpose, statutory basis, and prevailing methodologies; then, we identify key regulatory and policy shifts driving reform; and finally, we set out a coherent set of actionable recommendations.

3.1 Cross-subsidy surcharge

Purpose, legal basis, and design

Cross-subsidy has long been a central feature of India’s electricity tariff design framework. Commercial and industrial consumers pay tariffs above the discom’s average cost of supply (ACoS), enabling below-cost tariffs for agricultural and low-income domestic users. An assessment of 60 discoms for 2019 found that C&I consumers overpay by an average of INR 2.46/kWh and INR 1.35/kWh for C&I categories, respectively (Tyagi and Tongia 2023).

The CSS is anchored in Section 42(2) of the Electricity Act, 2003 (MoLJ 2003). It compensates discoms for the loss of cross-subsidy revenue when higher-tariff C&I consumers migrate to OA. It applies only to third-party OA transactions; captive and group-captive consumers are exempt under the Electricity Act. In practice, CSS constitutes the largest single component of OA charges and plays a decisive role in shaping both discom revenues and the economics of RE procurement (Gambhir et al. 2020). The act specifies that CSS should reflect the current level of cross-subsidy within the discom’s area of supply–a requirement that, as the analysis will show, is systematically violated in practice.

Apart from the Electricity Act, 2003, the design and application of CSS are governed by multiple regulatory instruments, including the policy guidance under the National Tariff Policy, 2006 (NTP) and its subsequent amendments in 2008 and 2016 (MoP 2016), as well as subordinate legislations, such as the Electricity Amendment Rules, 2022 and the Electricity (Promoting Renewable Energy Through Green Energy Open Access) Rules, 2022 (MoP 2022b). The NTP 2016 provides the operational guidance that CSS should neither stifle competition nor undermine discom viability. It also specifies that CSS should not exceed 20 per cent of the applicable consumer tariff and requires state electricity regulatory commissions (SERCs) to establish a trajectory for reducing cross-subsidies, gradually bringing tariffs for all consumer categories within ±20 per cent of the ACoS.

Subsequently, the Electricity (Amendment) Rules, 2022, capped CSS at 20 per cent of the ACoS (MoP 2022a), which differs from the provision under the NTP 2016. The GEOA Rules 2022 introduced additional provisions governing the CSS for green energy OA (MoP 2022b). The GEOA Rules specify that the CSS shall not increase by more than 50 per cent of the surcharge fixed in the year OA was granted, for a period of twelve years from the commissioning of the generating plant. Despite these overarching provisions, states continue to apply varying methodologies and interpretations in determining CSS, resulting in a lack of uniformity across jurisdictions.

Further, the recently notified Electricity (Amendment) Rules, 2026 (MoP 2026), simplified proportionality requirements for group-captive projects and clarified verification and appeals, thereby reducing litigation and compliance uncertainty. These changes are likely to improve the viability and scalability of captive-based renewable procurement for C&I consumers.

CSS should reflect the current level of cross-subsidy within the discom’s area of supply, violated in practice.

Drivers for reform

A series of regulatory, financial, and structural changes in India’s power sector are beginning to alter the relevance and effectiveness of the current CSS framework. These developments could prompt policymakers and regulators to reassess both the methodology for CSS and its role in an evolving electricity market.

Tariff rationalisation and solarisation of domestic and agricultural demand is leading to a reduction of cros subsidy requirement.

A. Declining cross-subsidy requirements

Impact of tariff rationalisation measures: One of the most significant developments in recent years is the gradual reduction in cross-subsidy requirements across states. The regulatory framework mandates the progressive alignment of the average billing rate (ABR) with the ACoS within a ±20 per cent band across consumer categories. As of FY2024–25, domestic tariffs in Bihar, Madhya Pradesh, Maharashtra, Tamil Nadu, and Karnataka are already above 90 per cent of ACoS. For agriculture, Bihar and Madhya Pradesh have met the ±20 per cent threshold (ETPI 2024). Karnataka has gone the furthest, establishing a trajectory to nearly eliminate crosssubsidy from tariff design by FY2027–28. These developments suggest that state governments are increasingly bearing a larger share of the subsidy burden through direct budgetary transfers rather than embedding it within tariff structures (Tripathi and Aggarwal 2025).

Impact of solarisation programmes: Central government schemes, such as Pradhan Mantri Kisan Urja Surakshaevam Utthaan Mahabhiyan Yojana (PM-KUSUM) and PM Surya Ghar: Muft Bijli Yojana, along with several state initiatives, aim to meet a substantial share of agricultural and household electricity demand through decentralised solar generation. PM-KUSUM targets the solarisation of 35 GW of agricultural demand by March 2026, while PM Surya Ghar aims to deploy 30 GW of rooftop solar for residential consumers by March 2027. These initiatives are expected to reduce both subsidy requirements and cross-subsidy burdens embedded within tariffs. For instance, Maharashtra estimates that feeder-level solarisation could reduce its annual subsidy outlay by around 45 per cent (from INR 10,000 crore to INR 5,500 crore), lower the cost of supply and reduce cross-subsidy requirements. This could potentially lower C&I tariffs by INR 1.0–1.5/kWh, making solarisation an attractive pathway for tariff rationalisation (MAHAVITARAN 2025; MAHAPREIT 2025).

Misalignment between cross-subsidy levels, CSS methodology, and intent under the Electricity Act, 2003: Cross-subsidy requirements are declining; however, CSS has not followed. Karnataka illustrates this divergence clearly: the cross-subsidy contribution of industrial (HT-2a) and commercial (HT-2b) consumers under the proposed FY2027–28 tariff trajectory is INR 0.17/kWh and INR 0.13/kWh, respectively. In contrast, the CSS approved by the regulator is INR 1.82/kWh, 11–14 times higher than the actual cross-subsidy contribution. Similar patterns are observed in Gujarat, Madhya Pradesh, Uttar Pradesh, and Rajasthan.

This divergence has a structural basis. Regulators compute CSS using voltage-wise cost parameters, while cross-subsidy contributions are assessed against the ACoS. Consumer tariffs are set with reference to ACoS rather than the voltage-wise cost of supply (VCoS). Therefore, CSS is anchored to voltage-level cost parameters, while the cross-subsidy embedded in tariffs is determined using average system costs–and the two routinely diverge (see Box 1). Our consultations indicate that SERCs are complying with the provisions of the NTP, which require CSS to be determined at the relevant voltage level, resulting in structural inconsistency.

Further, a review of financial disclosures from several large discoms suggests that CSS collections remain modest compared with the discoms’ overall revenue base. In many cases, annual CSS collections range between INR 200–300 crore, representing less than 0.5 per cent of the annual revenue requirement. Yet the administrative burden of verifying captive status for CSS exemptions is substantial, creating compliance costs for discoms, regulators, consumers, and generators alike.

These observations indicate that the policy objectives under the Electricity Act, 2003, and NTP 2016 have not been implemented in tandem. The NTP calls for progressive reduction of cross-subsidies in tariffs, while the Electricity Act requires CSS to reflect the current level of cross-subsidy. These two mandates should reinforce each other; however, in practice, the CSS formula has not tracked the decline in cross-subsidies, resulting in systematic over-recovery and highlighting the need to review it.

B. Discoms under-recovery due to CSS exemptions for captive consumption 

Under the Electricity Act, 2003, CSS applies only to third-party OA transactions, while captive consumption remains exempt. As a result, when C&I consumers migrate to captive arrangements, discoms lose the cross-subsidy revenue embedded in tariffs and do not receive compensation through CSS. In practice, this financial loss should reflect the foregone crosssubsidy contribution rather than CSS receipts. To partially offset this impact, several states levy electricity duties on captive consumption, which can moderate the net revenue loss for discoms (Kokate and Josey 2022).

As tariff reforms progressively align consumer ABRs with ACoS, the cross-subsidy embedded in C&I tariffs will shrink, and with it, the revenue discoms stand to lose when those consumers migrate to captive arrangements. In the long run, as tariffs become fully cost-reflective, the rationale for cross-subsidy disappears entirely, and CSS loses its purpose. Reform is therefore self-reinforcing, and every step towards ACoS alignment reduces the distortion that CSS was designed to address. Policy discussions are already moving in this direction. For instance, the draft Electricity (Amendment) Bill, 2025, proposes to phase out CSS for manufacturing enterprises, Indian Railways, and metro railways within five years. Once cross-subsidy is eliminated from tariff design, the distinction between captive and third-party OA also becomes redundant.

Implementing these reforms will require navigating significant political and institutional constraints. Tariff rationalisation often involves difficult trade-offs for state governments and regulators including balancing cost-reflective pricing with consumer affordability, improving discom finances while preserving C&I competitiveness, and introducing efficient price signals without undermining renewable investment certainty. Policymakers will therefore need to pursue these changes gradually while protecting vulnerable consumers and strengthening coordination between regulatory and fiscal institutions. Recognising these constraints is essential to ensure that reforms remain both practical and implementable.

Recommendations

Declining cross-subsidy requirements, potential over-recovery under the existing CSS methodology, and revenue risks for discoms arising from captive exemptions together warrant a reassessment of how CSS is computed and applied. The recommendations here propose immediate regulatory actions and longer-term structural reforms, organised by timeframe and responsible actor. Some actions may also affect other OA charges and will therefore require coordinated regulatory attention to ensure consistency across the broader tariff framework.

MoP must review the CSS methodology and, after consultation with states, notify a new framework.

3.2 Additional surcharge 

Purpose, legal basis, and design

The AS is levied under Section 42(4) of the Electricity Act, 2003. When C&I consumers procure electricity through OA, discoms may remain obligated to pay fixed charges under long-term PPAs that were originally contracted to serve those consumers. The AS enables discoms to recover unavoidable fixed costs arising from such stranded power purchase commitments. The AS applies only to third-party OA transactions, while captive and group-captive users are exempt. This distinction has been upheld in several Appellate Tribunal for Electricity (APTEL) and court judgments, including JSW Steel Ltd & Others vs Maharashtra Electricity Regulatory Commission & Others (2019).

The design and application of AS are governed by multiple regulatory instruments, including the NTP 2006 and subsequent amendments, the Electricity (Promoting Renewable Energy Through Green Energy Open Access) Rules, 2022, and the Electricity Amendment Rules, 2024. The NTP 2016 broadly establishes that AS should reflect only the actual stranded fixed costs arising from discoms’ power purchase commitments and should not undermine the viability of OA. It further clarifies that AS is distinct from network-related charges, which are recovered separately through wheeling and transmission tariffs.

Subsequent regulatory provisions have further refined the scope of AS. The GEOA Rules 2022 specify that AS shall not apply to green energy OA consumers if they continue to pay fixed charges to the discom. The Electricity Amendment Rules, 2024, also cap AS at the per-unit fixed cost of the discom’s power purchase. In addition, the rules introduce a sunset mechanism under which the surcharge must be reduced linearly from the level applicable in the year in which OA or general network access is granted and eliminated within four years. Despite these overarching provisions, states continue to apply varying methodologies and interpretations when determining AS, resulting in limited consistency across jurisdictions.

Drivers for reform

Several structural and regulatory factors limit the effectiveness of the current AS framework, including issues related to tariff design, stranded capacity attribution, and the treatment of certain OA transactions. The following subsections examine these challenges in detail.

A. Discom under-recovery due to captive exemptions

Under the Electricity Rules, 2005, captive and group-captive consumers are exempt from AS. Discoms challenged this exemption for several years; however, the Hon’ble Supreme Court recently upheld the legal position in Dakshin Gujarat Vij Company Limited vs Gayatri Shakti Paper & Board Limited and Another (2023). The exemption has significantly reduced AS-related revenues and has financial consequences for discoms. For instance, in Maharashtra, AS revenues declined by more than 80 per cent, from INR 575 crore in FY2017–18 to INR 109 crore in FY2023–24, following courts’ clarification that AS does not apply to group-captive projects (MSEDCL vs JSW Steel and Others 2021).

Renewable energy developers frequently structure projects as captive or group-captive arrangements by transferring the minimum required equity to consumers. This structure allows consumers to access OA power while avoiding both AS and CSS. Even where such transactions leave discoms with genuinely stranded contracted capacity, the current framework provides no compensatory mechanism. Several states levy electricity duties on captive consumption to partially offset this gap; however, these duties are state-specific and do not systematically address the underlying structural shortfall (Kokate and Josey 2022).

B. Inadequate assessment of curtailment reasons

Additional surcharge is justified only where OA transactions directly cause discoms to strand contracted capacity. In practice, however, regulators and discoms routinely attribute curtailment to OA volumes without adequately examining alternative causes, such as economic dispatch decisions (where discoms back down costlier power when cheaper sources are available), RE variability management, demand forecasting errors, or grid outages. Renewable energy developers and OA consumers have consistently contested this assumption, arguing that several factors unrelated to OA transactions also contribute to power curtailment.

In recent times, courts and tribunals have already scrutinised this assumption. In Lord Chloro Alkali Limited vs Rajasthan Electricity Regulatory Commission & Others (2025), the APTEL overturned Rajasthan’s regulator’s AS levy for FY2015–16, finding that the state had failed to establish a clear link between power curtailment and actual OA volumes. The ruling highlights the need for discoms to demonstrate that OA transactions directly result in stranded capacity before seeking compensation. To ensure that AS reflects genuine OA impacts, regulators should examine the underlying reasons for curtailment before attributing stranded costs to OA consumers. Figure 5 sets out key questions.

Regulators should examine the underlying reasons for curtailment before attributing stranded costs to OA consumers.

C. Discom under‑recover fixed cost due to inefficient tariff design

Regulatory proceedings across several states show that commissions apply varying methodologies to determine AS, a practice that RE developers and OA consumers frequently contest. Regulators and discoms often justify these approaches by arguing that discoms underrecover fixed costs due to the inherent design of electricity tariffs, and that AS is therefore required to compensate for the resulting revenue gap. Therefore, the strongest driver of AS is not OA itself, but the structural mismatch between how discoms incur costs and how tariffs recover them.

Discoms incur two types of costs: fixed costs associated with long-term power purchases, transmission, and distribution networks, and variable costs linked to the energy consumed from generators. Although fixed costs account for nearly half of a discom’s total expenses, fixed charges typically contribute only 15–20 per cent of total revenue (KERC 2025). The remaining 30–35 per cent of fixed costs is recovered through energy charges, creating a structural mismatch between cost recovery and tariff design. State-level data confirms the scale of this issue. In Delhi, regulators bundle more than 60 per cent of fixed costs into energy charges (DERC 2025). In Maharashtra, fixed charges account for only about 19 per cent of revenue, even though fixed costs represent nearly 57 per cent of total costs (MERC 2025). As a result, when consumers shift to OA and reduce their energy drawal from the discom, a significant share of fixed costs remains unrecovered, strengthening the regulatory justification for levying the AS.

An illustrative analysis of a 5 MW industrial consumer in Karnataka demonstrates how fixedcost recovery operates under discoms and OA-based power procurement. Table 2 summarises the assumptions and calculations used in this illustrative analysis, while Figure 6 presents the findings across scenarios.

In Scenario 1, the discom supplies the consumer’s entire demand. Despite the tariff structure recovering only 32 per cent of fixed costs through fixed charges, full fixed-cost recovery is achieved because the consumer pays energy charges on all units drawn, and energy charges carry the embedded fixed-cost component.

In Scenario 2, the consumer migrates 55 per cent of demand to third-party OA. The discom loses energy charge revenue on these units. The discom applies all applicable charges, including fixed charges on sanctioned load, wheeling charges, transmission charges, and AS. Even after applying these charges, a 6 per cent fixed cost remains unrecovered. For captive transactions, which are exempt from AS, the under-recovery increases to about 14 per cent.

Scenario 3 demonstrates that the entire issue can be addressed through tariff redesign. If fixed charges are increased by 41 per cent (from INR 385/kVA to INR 543/kVA) and energy charges are reduced by 20 per cent (from INR 6.47/kWh to INR 5.18/kWh), fixed costs are fully recovered through the fixed component of the tariff. When a consumer migrates to OA, the discom no longer loses fixed-cost recovery along with energy revenue, because fixed costs are no longer embedded in energy charges. As a result, AS becomes unnecessary, and the distinction between captive and third-party transactions becomes redundant.

This approach also aligns with the GEOA Rules 2022 and several state regulations, which specify that AS should not apply if a consumer pays the full fixed cost through tariffs. The assumption is that fixed charges are set at cost-reflective levels. Several states have begun moving in this direction. Karnataka has set a trajectory to increase fixed-cost recovery from 19 per cent to 38 per cent over FY2024–28. Maharashtra and Rajasthan have initiated similar, though more gradual, adjustments. Table 3 presents Karnataka’s trajectory across consumer categories. The analysis, therefore, shows that prudent tariff design alone can protect discom revenues while providing consumers greater price transparency. Once tariff rationalisation ensures adequate recovery of fixed costs, the rationale for levying AS weakens significantly.

These tariff changes will also alter the economics of OA procurement. As fixed charges rise and energy charges decline, C&I consumers will reassess their contract demand requirements and load-optimisation strategies. Such adjustments could encourage consumers to reduce contracted demand and invest in alternative supply options, such as solar and storage, particularly as technology costs continue to fall. Discoms therefore face a delicate transition: while higher fixed charges improve cost recovery, large and abrupt increases could accelerate migration away from discom supply

Recommendations 

A rational AS framework must balance the legitimate cost-recovery needs of discoms with the predictability and fairness required by OA consumers. The following recommendations propose a phased pathway to improve transparency, strengthen methodological rigour, and gradually phase out AS where tariff reforms reduce the need for stranded cost recovery.

3.3 Standby charge 

Purpose, legal basis, and design

Standby charges apply when OA consumers rely on the discom for backup supply–during generator outages, transmission constraints, or force majeure events. The discom steps in to ensure continuity of service. Standby charges compensate the discom for maintaining the reserve capacity and operational readiness required to provide backup.

Unlike CSS and the AS, standby charges are payments for a service rather than compensation for revenue loss. The discom acts as the supplier of last resort, maintaining the ability to meet sudden demand when the consumer’s primary power source fails.

The Electricity Act, 2003, does not explicitly define standby charges. State electricity regulatory commissions derive their authority to design such charges from their broader tariff-setting powers under the act. Policy guidance is also available through the NTP 2016 and the GEOA Rules 2022. The NTP states that when the generator supplying an OA consumer trips, the discom should provide a temporary supply at a tariff not exceeding 125 per cent of the applicable retail tariff. The GEOA Rules state that standby charges should not apply when the consumer provides at least 24 hours’ advance notice of the standby requirement, and, where levied, such charges should not exceed 10 per cent of the energy charges applicable to the relevant consumer tariff category.

Despite these guiding provisions, states have adopted widely different approaches to standby arrangements. The variation is substantial–it ranges from structured four-tier frameworks to no provisions at all.

Drivers for reform

Standby charges are a critical but underdeveloped component of the regulatory landscape. Most states lack a cost-reflective design, leading to significant under-recovery for discoms and weak economic signals for consumers.

A. Discom stand-by services are not cost-reflective, leading to cost under-recovery

Standby supply involves two distinct cost components. The first is capacity reservation cost–the fixed cost of maintaining generation capacity and system readiness regardless of whether backup power is drawn. The second is variable procurement cost–the cost of actually sourcing electricity when a consumer calls on standby. A cost-reflective standby framework recovers both through a two-part tariff: a fixed charge for capacity reservation and an energy charge for actual drawal. The MoP’s 2017 Consultation Paper on Open Access recommended exactly this structure (MoP 2017).

Although there is limited quantitative evidence on the extent of discom under-recovery from standby charges, insights can be drawn from the current design of standby charges and their linkage with fixed-cost recovery, as discussed in Section 3.2 on AS. In practice, most states lack a structured and cost-reflective framework. As shown in Figure 7, standby charge mechanisms vary widely across states. Some states apply a simple multiplier to energy charges (such as Karnataka, Haryana, and Gujarat), while others combine demand and energy charges (such as Maharashtra and Punjab). A few states, including Tamil Nadu and Rajasthan, lack an explicit framework, leading to ad hoc and non-transparent practices. The variation across states highlights the absence of a consistent regulatory framework for valuing backup capacity and recovering associated system costs.

Punjab provides a clear illustration of the limitations of even relatively advanced frameworks. The state has a formal two-part structure–one of only two states in Figure 7 do so. However, the capacity reservation charge of INR 50–60/kVA per month recovers only about 21 per cent of the estimated monthly fixed cost of INR 280/kVA (PSERC 2025). An energy charge of 125 per cent of the applicable tariff for actual drawal is also applicable. A 5 MW consumer contracting standby without drawing power pays approximately INR 3 lakh per month, leaving an estimated fixed-cost gap of INR 11 lakh per month, which is approximately INR 1.3 crore annually. In the absence of cost-reflective standby charges, discoms socialise these backup costs across all consumers or resort to ad hoc surcharges.

B. Designing cost-reflective standby charges is challenging

Designing fair and cost-reflective standby charges is not straightforward. Discoms and regulators face several structural challenges in pricing standby services appropriately (Figure 8).

Challenge 3 is directly linked to the tariff rebalancing argument presented in the AS section. As states correct the fixed–variable cost bundling problem, standby pricing becomes simultaneously easier to implement, because the risk of embedded fixed-cost double-charging diminishes.

Given these challenges, regulators require a structured and transparent approach to standby provisioning. Maharashtra demonstrates that a workable solution exists despite these challenges. Its four-tier commitment framework resolves Challenge 1 (capacity attribution) through contractual commitments, and Challenges 2 and 4 (market pricing and DSM [deviation settlement mechanism]) by anchoring charges to demand rates rather than spot prices. Figure 9 illustrates this structure.

The framework has three key advantages. First, advance commitments allow discoms to estimate reserve requirements, directly addressing Challenge 1. Second, the escalating penalty structure creates strong price signals against unplanned drawal, reducing the exposure to market price volatility from Challenge 2 (Kokate and Josey 2025). Third, anchoring charges to demand rates rather than energy rates keeps the framework compatible with tariff rebalancing–as fixed charges rise, standby charges increase proportionally without double-counting.

Looking ahead, two structural shifts could transform how standby services are priced. The growth of ancillary services and balancing markets may enable reserve capacity to be procured competitively rather than through administrative tariffs. In parallel, digitalisation and advanced metering may enable real-time standby pricing linked to grid conditions, allowing consumers to manage standby risk through storage or third-party flexibility providers.

Recommendations

A rational standby charge framework must balance two objectives: enabling discoms to recover the cost of maintaining reserve capacity while ensuring predictability and fairness for OA consumers. At present, many state-level mechanisms remain ad hoc or poorly aligned with the underlying cost drivers of standby supply. The following recommendations set out a phased roadmap to improve transparency, strengthen tariff design, and integrate standby provisioning into broader system planning.

3.4 Banking charge 

Purpose, legal basis, and design

Renewable energy banking allows generators to inject surplus electricity into the grid and withdraw an equivalent amount later when their own generation declines. The grid temporarily absorbs the surplus and returns energy when required. Like standby charges, banking is a payment for a grid-balancing service rather than compensation for revenue loss. By enabling temporal adjustment between generation and consumption, banking helps consumers manage renewable variability and improves the utilisation of intermittent resources.

India introduced RE banking in 1986 in Tamil Nadu for wind generators as a promotional mechanism to support early RE deployment. States such as Maharashtra and Karnataka allowed annual banking with minimal or no charges, enabling generators to bank most of their surplus RE and withdraw it within the settlement period. These policies were instrumental in scaling renewable capacity when technology costs were high and grid integration frameworks were still being developed.

As RE costs fell from approximately INR 14.5/kWh in 2010 to below INR 3/kWh today, the economics of banking changed (Casey 2024). States now apply banking charges typically in the range of 8–10 per cent of the banked energy, with settlement timelines varying across states, including intraday, monthly, and annual adjustments, depending on regulatory frameworks.

To harmonise banking provisions across states, the central government notified the GEOA Rules 2022. The rules state that banking, where permitted, should be settled at least monthly and capped at 8 per cent of banked energy. The rules also specify that states should allow banking of RE up to 30 per cent of the consumer’s total electricity consumption in a month, subject to regulatory approval.

Drivers for reform

Banking originally functioned as a promotional instrument but has increasingly become a source of operational and financial pressure for discoms, particularly as solar penetration created large midday surpluses that consumers banked and then withdrew during evening peak hours at the discom’s cost. The following factors explain why several states are revisiting their banking frameworks.

A. Banking services are often not cost-reflective

When consumers bank energy, discoms incur two distinct costs. The first is a back-down cost: surplus RE injected during midday forces discoms to curtail contracted thermal generation while continuing to pay fixed-capacity charges. The second is a peak procurement premium: when consumers withdraw banked energy, typically during evening peak hours, discoms must source replacement power from short-term markets at prices substantially higher than what they would have paid from their contracted portfolio. Figure 10 shows why this mismatch is structural rather than incidental.

When consumers bank energy, discoms incur two distinct costs: back down cost and peak procurement premium.

Discoms, therefore, argue that banking effectively forces them to absorb the cost of balancing renewable variability for OA consumers (UPPCL 2024). For instance, an assessment of Karnataka’s banking framework estimated that discoms incurred losses of INR 0.50–0.70/kWh due to banking provisions in FY2020–21, amounting to approximately INR 253–350 crore for around 5,000 MU of OA consumption (Dixit et al. 2022). Such experiences have prompted regulators to reassess whether existing banking charges adequately reflect underlying system costs.

B. States are tightening banking provisions and moving towards a de facto ‘no banking’ regime

Several states have begun modifying banking rules to better align withdrawals with evolving system conditions (Gulia et al. 2021)

In Maharashtra, recent regulatory changes have linked banking withdrawals more closely with time-of-day (ToD) scheduling (MERC 2025). These changes were made to reflect the state’s evolving supply profile, where growing solar capacity is expected to create substantial midday generation surplus. Under the revised framework, the ability to shift large volumes of low-cost daytime solar generation to high-value other periods is significantly constrained. As a result, the effective substitution of discom supply through OA renewable procurement may decline from now 50–65 per cent of a consumer’s demand to around 30–40 per cent, depending on project configuration. Although elements of this framework have faced legal challenges and remain under review, the regulatory direction indicates increasing scrutiny of banking arrangements (Deshpande 2025).

Rajasthan has retained annual banking but introduced several restrictions. The state now limits banking primarily to captive renewable projects and excludes third-party OA transactions. It also caps the banked quantum at 25 per cent of monthly injected energy or 30 per cent of the consumer’s monthly consumption, whichever is higher (RERC 2023).

Gujarat continues to permit banking but levies one of the highest charges in the country, currently around INR 1.50/kWh (Mathew 2026). The regulator has also commissioned a study to assess appropriate banking charges under different renewable penetration scenarios (Kumar 2023). Although the status of this study remains unclear, the approach indicates a shift towards cost-reflective pricing of banking services.

C. Banking may be a transitional instrument as alternative balancing mechanisms mature

Battery storage costs have fallen from approximately INR 13,860/kWh in 2020 to around INR 8,400/kWh in 2025 and are projected to decline further (Chojkiewicz et al. 2025). The day-ahead market and real-time market have expanded significantly, creating new flexibility mechanisms for managing short-term imbalances (Jarbratt et al. 2023; Das and Rodrigues 2025). Green hydrogen and hybrid renewable-plus-storage procurement are emerging as additional alternatives. As storage costs decline and market mechanisms mature, the role of banking is becoming increasingly redundant. The question is therefore shifting from whether banking should continue in its current form to how and at what pace states should transition from banking-dependent procurement to market-based balancing mechanisms.

Recommendations

A reformed banking framework must balance grid reliability, discom cost recovery, and operational flexibility for RE consumers. As renewable penetration increases and alternative balancing mechanisms emerge, regulators will need to gradually transition banking from a promotional policy instrument to a priced grid-balancing service. The following recommendations outline a phased pathway to support this transition while minimising regulatory uncertainty for market participants.

3.5 Parallel operation charge (POC) 

Purpose, legal basis, and design

Parallel operation charges–also known in some states as grid support charges (GSC)–are levied on captive power plants (CPPs) that operate in parallel with the grid. These charges compensate discoms for grid support services provided to captive users, including maintaining stability, offering backup during outages, and managing voltage and frequency imbalances. Discoms argue that CPPs, while drawing reliability from the wider network, also introduce what is termed ‘grid pollution’–disturbances in power quality arising from harmonic injection, reactive power imbalances, voltage dips, and frequency fluctuations. These technical disruptions, they contend, impose measurable costs on the distribution system, justifying a compensatory levy.

The Electricity Act, 2003, empowers SERCs under Sections 86(1)(f) and 86(1)(g) to determine fees, which form the legal basis for the levy of POC. The Supreme Court, in its 2019 ruling (Civil Appeal 4569 of 2003), upheld POC as a legitimate “service charge” payable to discoms, affirming its distinct legal standing from other OA charges. However, there is no national framework governing POC, and it is levied only in states where SERCs have exercised their powers under Section 86.

Over the years, POC has evolved through a series of judicial and quasi-judicial rulings. Decisions of the Appellate Tribunal for Electricity in certain cases have clarified three key aspects: (i) SERCs hold jurisdiction over the charge; (ii) POC applies only to co-located captive loads; and (iii) POC is distinct from CSS and AS (Rain CII Carbon (Vizag) Ltd vs Andhra Pradesh Electricity Regulatory Commission & Others [2023]; Hindalco Industries Limited vs Madhya Pradesh Electricity Regulatory Commission & Others [2021]; Salasar Steel & Power Ltd vs Chhattisgarh State Power Distribution Company Ltd & Another [2016]). Researchers have aptly termed it a “litigious levy” in their examination of this jurisprudence (Sanjay et al. 2025, 1). Its incidence and structure have largely been charted in courts and tribunals; however, these orders have resulted in inconsistent methodologies across states.

Drivers for reform

The case for reforming POC arises from both design inconsistencies and a shifting technological and regulatory landscape. Originally designed as a compensation mechanism for discoms managing grid disturbances from large synchronous captive units, the rationale and methodology behind POC are increasingly under scrutiny. The most pressing issues are detailed here:

A. Evolving regulatory mandates on power-quality monitoring

Amendments to the CEA’s Technical Standards for Connectivity to the Grid (2019) now mandate both discoms and bulk consumers to undertake continuous power-quality monitoring (CEA 2019). Bulk consumers are required to install power-quality meters and share data with discoms at specified intervals, with compliance required within 12 months of the amendment’s notification. Simultaneously, discoms must install such meters at a minimum of 33 per cent of their 33 kV substations annually, achieving full deployment within three years. The regulations also require periodic measurement of parameters such as voltage sag, swell, flicker, and harmonics, with data to be shared with consumers.

B. A patchwork of methodologies

There is no single framework governing POC (see Figure 11). Some states, such as Madhya Pradesh and Gujarat, continue to rely on installed capacity, reflecting legacy approaches from the early 2000s when monitoring infrastructure was still in its infancy. Andhra Pradesh and Telangana, in contrast, link the charge to utilities’ repair and maintenance (R&M) expenses, arguing that this better reflects the cost of grid upkeep. Rajasthan, after commissioning a study by the Electrical Research and Development Association (ERDA), introduced a hybrid framework, using base MVA capacity for conventional captive plants and power-quality-linked computation for renewable ones. This heterogeneity raises concerns about fairness and comparability across jurisdictions. As a result, captive consumers (especially those transitioning to RE-based CPPs) face cost uncertainties that affect project viability.

C. Double counting and design overlap

Across several states, POC overlaps with existing fixed-demand charges or standby charges, raising concerns of double recovery (see Figure 11). Captive consumers argue they already pay for grid reliability through sanctioned-load demand charges, and that imposing POCs effectively charges them twice for the same reliability cushion. This undermines transparency for C&I consumers and increases litigation risks. Discoms counter that contract demand only secures capacity; it does not cover the instantaneous reactive power and voltage balancing required for parallel operation (APERC 2025). In practice, this distinction is difficult to verify without actual power-quality measurement data, which is precisely what the CEA’s 2019 mandate is intended to provide.

D. Transparency and evidence deficit

Despite its technical justification, POC lacks a robust empirical foundation. Most SERCs rely on limited technical studies, often based on fewer than 10 plants–an inadequate sample given India’s 72.8 GW captive capacity across nearly 2,900 large plants of 1 MW+ capacity (India Infrastructure Research 2021). No state publishes a detailed cost breakdown or measurable benefits derived by discoms from parallel operation. As a result, captive users argue that they pay a ‘black-box’ levy, as they have no visibility into how grid pollution is quantified, how much of the revenue is actually used for grid improvement, or even whether discoms are monitoring harmonics as required. For regulators, this lack of evidence limits their ability to fairly adjudicate POC petitions or to challenge poorly substantiated claims. Discoms, too, are disadvantaged, as the lack of data prevents them from justifying differentiated treatment across technology types or system configurations.

E. Outdated logic of levying POC with rising renewables

Captive generation has evolved significantly, with wind–solar hybrids, waste-heat recovery, and biomass cogeneration increasingly being preferred over traditional coal-based captive units. However, POC remains calibrated to the operational patterns of old thermal plants. Captive RE plant owners note that RE-based CPPs inject fewer disturbances, operate intermittently, and often provide ancillary flexibility through storage, yet are still billed at par with fossil-based units (APERC 2025). Studies also show that inverter-based renewables can introduce harmonics, which are mitigated through in-built harmonic filters in advanced inverters (Kaur and Bath 2025). As power-quality meters mandated under CEA’s 2019 Connectivity Regulations become operational, discoms will need to move away from presumptive levies and adopt performancebased standards. For discoms, this transition will also require proactive investment in monitoring infrastructure, without which future POC filings may be contested or rejected.

Recommendations

The structure and levy of POC vary widely across states due to limited technical evidence and evolving jurisprudence. This section outlines a roadmap for harmonised, evidence-based regulation that balances discom cost recovery with the fair treatment of captive RE generators.

3.6 Wheeling charge 

Purpose, legal basis, and design

Wheeling charges represent the cost paid by users (including OA consumers) for using the discom’s network to transport electricity from the point of injection to the point of consumption. In essence, they are the fee for using the grid’s wires similar to a toll paid for using a public road. These charges are levied to compensate discoms for maintaining and operating the network that enables the physical delivery of electricity.

Wheeling charges are derived from Section 42(2) of the Electricity Act, 2003, which mandates distribution licensees to provide non-discriminatory OA to their network, subject to the payment of applicable wheeling charges as determined by SERCs.

The NTP 2016 reinforces the principle of cost-reflective network pricing, encouraging SERCs to establish transparent methodologies for computing wheeling charges based on voltage level, energy flow, and network usage. More recently, the Electricity (Amendment) Rules, 2024, provide further regulatory clarity by prescribing that wheeling charges be computed as the ratio of aggregate revenue requirement (ARR) towards wheeling to the total energy wheeled during the year, thereby standardising the basic computation principle across states.

Drivers for reform

Wheeling charges are among the least contested among discoms, RE developers, and consumers. However, our consultations and regulatory review indicate that persistent gaps in data systems and cost allocation practices undermine the transparency and accuracy of these charges. If wheeling charges fail to reflect true infrastructure costs, discoms may underinvest, jeopardising the financial viability of future grid capacity. To unpack these issues, Annexure I maps the prevailing stepwise methodology for computing wheeling charges, highlighting how current stages fall short in practice. The key structural challenges that necessitate reform are as follows:

A. Lack of voltage-wise asset accounting

Most discoms lack an audited and granular record of fixed assets segregated by voltage level. In practice, asset costs are allocated across 33 kV, 11 kV, and low tension (LT) systems using proxy indicators, such as line length or transformation capacity. While pragmatic, this approach is an approximation that may not accurately reflect the value or utilisation of assets serving different consumer categories. Completing the voltage-wise fixed-asset register, as mandated in several states’ tariff regulations, would enable future wheeling-charge calculations to be based on verifiable data rather than derived estimates.

B. Use of estimated network costs based on standard material rates

In several cases, where the present cost of network assets cannot be ascertained from the fixed-asset register, discoms estimate costs using store-rate circulars for standard line spans and transformers. While this provides a temporary basis for apportionment, it can distort asset valuation, particularly in networks with a significant share of legacy infrastructure.

C. Reliance on benchmark loss assumptions

Several discoms lack metering at intermediate voltage levels, leading regulators to rely on benchmark or historical loss percentages from earlier orders. This can obscure actual network efficiency and unfairly distribute losses across voltage levels. Progressive roll-out of feeder and substation metering, combined with periodic energy audits, would enable the segregation of actual losses, thereby improving the accuracy of wheeling-charge determination.

D. Uniform charges obscure cost diversity, but locational pricing raises equity concerns

maintain uniform tariffs across states, many commissions prescribe an average wheeling charge applicable to all discoms. While administratively convenient, this averaging can conceal significant cost differences between urban and rural networks or between developed and lagging service areas. However, moving towards region-specific wheeling charges also raises equity concerns. Network investments in one region may be driven by generation or load located elsewhere–for instance, distribution infrastructure built near renewable clusters may primarily serve demand centres located outside that region. Assigning higher wheeling charges to consumers in such cases could therefore shift system costs onto consumers who are not the primary beneficiaries. As improved network data becomes available, regulators will need to balance cost transparency with tariff equity when considering more granular pricing.

Consumers have repeatedly raised these concerns in regulatory proceedings before various SERCs. Table 4 illustrates the diversity in state practices across key components of wheelingcharge computation.

Recommendations 

Wheeling charges often misrepresent actual network costs due to outdated metering, asset records, and accounting practices. This section identifies critical reforms to improve cost accuracy, enhance transparency, and enable discom-wise, voltage-level tariffs. It recommends phased reforms in metering, asset mapping, and accounting to support fair, data-driven charge design in a high-renewable grid.