Corporate Clean Energy Transition in India: Tariff Reforms & Decarbonisation

REPORT

Enabling Corporate India's Clean Energy Transition

Reforming Open Access Framework and Tariff Design for the Next Decade

21 May, 2026 | Power Markets

Prateek Aggarwal, Vishal Tripathi and Harsha V. Rao

Suggested Citation: Aggarwal, Prateek, Vishal Tripathi, and Harsha V. Rao. 2026. Enabling Corporate India's Clean Energy Transition: Reforming Open Access Framework and Tariff Design for the Next Decade. New Delhi. Council on Energy, Environment and Water.

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Overview

A manufacturing-led economic transformation, anchored by emerging sectors such as AI-enabled digital infrastructure and green hydrogen, is one of the pillars of India's Viksit Bharat 2047 ambition. Manufacturing’s share of GDP is targeted to rise from around 17 per cent today to 25 per cent by 2047. Achieving this goal will depend on the ability of Indian businesses to remain competitive in both domestic and global markets. Yet, in an increasingly volatile geopolitical environment, businesses are becoming more vulnerable to energy supply disruptions and price volatility, with significant implications for their competitiveness.

The need to enhance competitiveness has driven Commercial and Industrial (C&I) consumers to widen their renewable energy (RE) procurement choices beyond distribution companies (discoms). Discoms and non-discom RE routes accounted for ~23 per cent of C&I electricity consumption in 2025. Three structural shifts are now redefining corporate RE procurement. First, the sharp decline in storage costs is enabling reliable, dispatchable renewable power to emerge as a cost-competitive and domestically available solution. Second, evolving global standards are placing increasing pressure on companies to decarbonise their operations and supply chains. Third, ongoing regulatory and retail tariff reforms are pushing towards mechanisms that ensure C&I consumers fairly compensate discoms for the services they provide. Together, these trends are transforming both the economics and architecture of corporate clean energy procurement, while the existing open access framework has yet to evolve in step with these changes.

Against this backdrop, this report analyses the interaction between the ongoing tariff rationalisation efforts and the open access charges framework and how the two remain disconnected. We studied six open access (OA) charges that govern this market: cross-subsidy surcharge (CSS), additional surcharge (AS), standby charge, banking charge, parallel operation charge (POC), and wheeling charge. We examine how each charge is designed, where and why it fails, and what specific reforms are needed to create a level playing field across the discom and non-discom routes.

Key insights

The report identifies three structural failures, namely inefficient tariff design, the absence of empirical data, and state-level fragmentation that undermine the current OA charges framework.
The cross-subsidy surcharge formula is structurally disconnected from actual cross-subsidy levels. For example, in Karnataka, CSS is set at INR 1.82/kWh, which is 11 to 14 times higher than the actual cross-subsidy contribution of HT industrial consumers. Similar patterns are observed in Gujarat, Madhya Pradesh, Uttar Pradesh, and Rajasthan.
Only 15–20 per cent of discom revenue comes from fixed charges, despite fixed costs comprising nearly half of total expenditure. If Karnataka's tariff structure were rebalanced (i.e. fixed charges increased by 41 per cent, energy charges reduced by 20 per cent), the discom's fixed-cost recovery gap disappears entirely, and the additional surcharge becomes structurally redundant.
Standby charge frameworks vary widely across states, from Maharashtra's four-tier commitment structure to no formal provisions at all in Tamil Nadu and Rajasthan. Even Punjab's two-part standby tariff, one of the few states to separate capacity reservation from energy drawl, recovers only 21 per cent of the estimated monthly fixed cost of maintaining backup capacity.
Leading C&I consumers are already moving beyond the current framework, contracting firm renewable power with battery storage, signing round-the-clock agreements backed by long-duration pumped hydro, and deploying co-located solar, wind, and battery systems. The procurement model is shifting from annual energy volume to assured supply per 15-minute time block.
The report's recommendations are organised around addressing four challenges: first, correcting the tariff distortions that make compensatory surcharges redundant; second, build the evidence base required for rationalising charges accurately; third, redesign charges to reflect the costs they are intended to recover, and fourth, strengthen market mechanisms that can, over time, replace administrative charges.

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Prateek Aggarwal

Programme Lead

prateek.aggarwal@ceew.in

“In a world of energy supply shocks and price volatility, corporate renewable energy procurement is core to India's industrial competitiveness and energy security. C&I consumers account for nearly half of India's electricity demand, yet renewables meet only around a quarter of it. Unlocking the next phase requires reform across all procurement pathways, namely open access, captive, and discom-supplied 24/7 RE, and the regulatory enablers that govern each.”

Executive summary

A manufacturing-led economic transformation, supported by the rise of sunrise sectors such as AI-driven digital infrastructure and green hydrogen, is one of the pillars of India's Viksit Bharat 2047 ambitions. Manufacturing's share of GDP should rise from around 17 per cent today to 25 per cent by 2047 (Jha 2025), a shift also central to capitalising on the China+1 opportunity as global supply chains diversify away from concentrated manufacturing bases (Debroy and Sinha 2024). Realising this ambition rests on Indian businesses being competitive across domestic and international markets. But in a geopolitically uncertain world, corporates are increasingly exposed to energy supply and price shocks that put their competitiveness at risk. Industrial investment decisions, with 20–25 year horizons, require long-term electricity price certainty and revenue visibility. Clean, firm, and competitively priced power is now a precondition for attracting this investment, not a sustainability overlay on top of it.

This is already changing how large electricity consumers think about clean energy procurement. The need to enhance competitiveness has driven commercial and industrial (C&I) consumers to widen their renewable energy (RE) procurement choices beyond distribution companies (discoms). Non-discom RE routes, including third-party open access (OA) and captive arrangements, accounted for around 10 per cent of C&I electricity consumption in 2025. When combined with grid-embedded RE supplied through discoms, renewables meet approximately 23 per cent of C&I electricity demand.1 Three megatrends are now shaping how corporates source power. First, the rapidly falling cost of storage is making on-demand, dispatchable RE, a competitive and indigenously available option. Second, global frameworks are increasingly enforcing stringent standards on the carbon footprint of corporate operations and supply chains. Third, regulatory and retail tariff reforms require migrating C&I consumers to fairly compensate discoms for the services they provide. Together, these forces are reshaping not only what corporations procure, but also how they procure.

Recent actions by the central government including the four-year sunset provision for the additional surcharge under the Electricity Amendment Rules 2024 (MoP 2024a), the draft Electricity (Amendment) Bill 2025's proposal to phase out cross-subsidy for manufacturing, Indian Railways, and metro rail within five years (MoP 2025a), and the simplification of groupcaptive proportionality requirements under the Electricity Amendment Rules 2026 (MoP 2026), have begun to address parts of the problem. At the state level, Karnataka has set a trajectory to raise fixed-cost recovery from 19 to 38 per cent by FY2028 (KERC 2025). These are material developments, however, they do not completely address the underlying problem of discoms' cost underrecovery and a conducive framework for OA. Our analysis examines some of these developments, and recommendations set out in this report are meant to complement these ongoing efforts.

Tariff reforms and rising decarbonisation pressures are simultaneously reshaping the OA landscape

India's OA framework for corporate RE procurement is caught between two countervailing pressures. On one hand, tariff reforms across states are correcting long-standing distortions in electricity pricing. In many states, C&I consumers have historically cross-subsidised other consumer categories through higher tariffs. OA-based RE procurement allowed these consumers to procure RE at significantly lower rate than than grid power. As states rationalise tariffs and revise OA charges, the cost arbitrage is narrowing. On the other hand, decarbonisation pressures on Indian corporates are intensifying rapidly. Regulatory mandates, global carbon border adjustment mechanisms, investor-driven environmental, social, and governance (ESG) requirements, and supply-chain pressures from multinational buyers are turning RE procurement into a compliance necessity rather than a cost-driven choice.

Positioned at the intersection of these two shifts, the current OA charges framework is no longer adequate for the decade ahead. It undercompensates discoms for some of their legitimate costs and exposes C&I consumers to unpredictable, litigation-prone OA charge levies. Yet in CY2025 alone, solar OA additions reached 7.8 GW. Overall, C&I consumers contracted over 36 GW of RE capacity, with 45 GW more under development, and a further 100+ GW of procurement expected over 2030–35 that will need to include firming and storage technologies suited to a high-RE grid (Kothamasu 2025; Mercom India 2025). Table ES1 provides a diagnostic summary of how the six OA charges undermine discom cost recovery and distort the price signals for C&I consumers.

Table ES1. How OA charges undermine discom recovery and distort consumer signals

Charge	How discoms under-recover	How it distorts consumer signals	Root failure
Cross-subsidy surcharge (CSS)	On the one hand, captive and group-captive consumers are exempt from CSS, leading to a loss of cross-subsidy revenue. On the other hand, in several states, CSS levels exceed the actual cross-subsidies paid by C&I consumers.	CSS is not calibrated to the actual cross-subsidy embedded in tariffs. Even as tariff reforms reduce cross-subsidies, consumers continue to pay elevated CSS due to the disconnect between the Average Cost of Supply and the Voltage-wise Cost of Supply (ACoS–VCoS) and CSS methodology.	Tariff design
Additional surcharge (AS)	Fixed costs are largely recovered through energy charges. When consumers migrate, discoms lose the embedded fixed-cost recovery that AS cannot fully offset. In Karnataka, a 5 MW OA consumer contributes to a 6–14% fixed-cost under-recovery despite the AS levy.	AS is not consistently linked to demonstrable stranded capacity. In practice, it is applied under broad assumptions, leading to contested, non-causal pricing.	Tariff design
Standby charges	Most states recover only a fraction of the fixed cost of maintaining backup capacity, as charges are based on energy drawal rather than capacity reservation. Punjab’s two-part structure recovers only 21% of the estimated fixed-capacity costs.	The absence of a two-part tariff means consumers do not bear the true cost of maintaining standby capacity. Backup is effectively under-priced and socialised across the system.	Design and data gap
Banking charges	Discoms incur back-down costs and peak procurement premiums that are not fully recovered under capped banking charges.	The regulatory cap on banking charges prevents cost-reflective pricing. States respond by restricting banking volumes instead of pricing the service appropriately, undermining procurement certainty.	Design and data gap
Parallel operation charges (POC)	Charges are based on limited studies and lack empirical grounding across the large captive fleet. No state publishes a cost justification.	POC is not linked to the actual impact on power quality. Uniform or presumptive charges apply regardless of technology, overstating costs for RE-based captive plants.	Data deficit
Wheeling charges	Network costs are allocated using proxies due to incomplete asset and loss data, leading to approximations in cost recovery.	Consumers face averaged, non-granular charges that do not reflect voltage-wise or locational network costs, limiting their ability to make efficient procurement decisions.	Data deficit

Source: Authors’ analysis

Note: ACoS (Average Cost of Supply) is the discom's total approved expenditure divided by total energy sold, yielding a single system-wide per-unit cost. VCoS (Voltage-wise Cost of Supply) disaggregates this cost by the voltage level at which consumers are connected, reflecting that serving consumers at higher voltages involves fewer distribution assets and lower losses, and therefore costs less than the system average.

In parallel, decarbonisation pressures are becoming more binding. Domestic policies such as renewable consumption obligations and the Carbon Credit Trading Scheme are introducing compliance requirements for industrial consumers. International mechanisms such as the EU’s CBAM will penalise carbon-intensive exports of steel, cement, aluminium, and fertilisers from the late 2020s (Singh et al. 2025). The Securities and Exchange Board of India’s (SEBI) Business Responsibility and Sustainability Reporting framework mandates emissions disclosures and assurance for top-listed companies. Sustainability-linked loans now tie borrowing costs directly to emission reduction targets (Climate Bonds Initiative 2025). Apple’s commitment to a 100 per cent carbon-neutral supply chain has driven over 250 suppliers across 28 countries, including India, to adopt verified renewable procurement (Apple 2023). These developments are not voluntary signals but contractual, regulatory, and commercial obligations with direct financial consequences.

Three structural failures undermine the current OA charges framework

This report analyses six OA charges–cross-subsidy surcharge (CSS), additional surcharge (AS), standby charges, banking charges, parallel operation charges (POCs), and wheeling charges–in terms of purpose, reform drivers, and actionable recommendations. Across all six, a common cluster of problems recurs, which can be distilled into three structural failures.

A. Inefficient tariff design makes cost recovery structurally impossible

Only 15–20 per cent of discom revenue comes from fixed charges, despite fixed costs comprising nearly half of discoms’ total expenditure. When consumers migrate to OA, discoms lose the contribution toward fixed costs embedded in energy charges–a loss that the compensatory additional surcharge cannot fully offset. An illustrative analysis of a 5 MW Karnataka consumer shows that, even with AS levies, the discom faces a 6 per cent fixed-cost under-recovery in case of third-party OA, which rises to 14 per cent for captive arrangements (which are exempt from AS). Cross-subsidy surcharges further compound the distortion: in Karnataka, the CSS is set at INR 1.82/kWh, 11–14 times higher than the actual cross-subsidy contribution of high tension (HT) industrial consumers under the proposed FY2027–28 trajectory. The root problem is not the surcharge rate; it is the inefficient tariff design.

B. The data needed to set accurate charges is absent in most states

Studies on POCs cover fewer than 10 plants, despite there being ~73 GW of captive capacity. In four of six states, wheeling charges rely on ratio-based asset splits because updated fixed-asset registers are unavailable. Several discoms lack metering at intermediate voltage levels, leading regulators to adopt benchmark or historical loss percentages from earlier orders. Banking cost studies are largely absent. In the absence of such data, OA charges that are precise in form but approximate in substance.

C. Methodological divergence across states creates regulatory unpredictability

Standby frameworks range from Maharashtra’s four-tier commitment structure to no provisions at all in Tamil Nadu and Rajasthan. Rates for POC vary by more than a factor of 10 across states that use the same nominal methodology. Banking rules have been revised retroactively in Maharashtra. For C&I consumers making 15–25 year investment decisions, this level of regulatory unpredictability is a material barrier to procurement at scale.

The market is not waiting for the framework to catch up

Corporate RE procurement in India is undergoing a structural shift, from volume-based annual energy accounting to reliability-centric portfolio design measured in 15-minute time blocks. Leading C&I consumers, such as Hindustan Zinc, have contracted 530 MW of firm RE with battery storage, securing assured delivery in every 15-minute time block. Hindalco and ArcelorMittal have each signed round-the-clock (RTC) RE agreements backed by long-duration pumped-hydro storage. UltraTech Cement has deployed co-located solar, wind, and battery storage to enhance on-site operational resilience. These are not pilot projects but reflect a procurement transformation already underway. Table ES2 maps the evolution of the C&I RE procurement model and its direction.

This transformation requires a fundamentally different regulatory foundation: one that supports procurement models that combine RE with storage, flexibility, and market-based balancing, rather than one built around administratively determined charges and limited data transparency.

Table ES2. C&I renewable energy procurement is shifting from cost arbitrage to reliability driven strategic procurement

	Typical coverage	Balancing mechanism	Delivery metric
Cost arbitrage era: Plain solar–cost-driven procurement
Driver: Lower tariff vs grid supply	30–50% of annual demand	Annual banking with generous OA provisions	Annual energy volume (MU)
Hybrid scale-up era: Solar–wind hybrid–expanded demand coverage
Driver: Cost savings combined with greater RE displacement	50–65% of annual demand	Monthly banking with increasing Time of Day (ToD) alignment	Annual energy with seasonal profiling
Reliability and compliance era: Firm RE with storage–assured delivery
Driver: Compliance requirements (ESG mandates, CBAM, RCOs) and tightening banking restrictions are pushing consumers toward assured delivery. The GHG Protocol Scope 2 revision proposes hourly matching for reporting, making grid-level emission optimisation essential to substantiate corporate sustainability claims.	Near-100%, including peak hours	Battery energy storage systems (BESSs), pumped hydro, and portfolio-based dispatch	Assured supply at 15-minute intervals

Source: Authors’ compilation based on stakeholder consultations and Hindustan Zinc (2025); Greenko Group (2022); Hindalco (2022); ArcelorMittal (2025); Gentari (2025), and UltraTech Cement (2025).

Recommendations

The report's recommendations are organised around addressing four challenges: first, correct the tariff distortions that make compensatory surcharges redundant; second, build the evidence base required for rationalising charges accurately; third, redesign charges to reflect the costs they are intended to recover; and fourth, strengthen market mechanisms that can, over time, replace administrative charges. Without progress on the first challenge, the remaining three can only partially succeed. Each recommendation is mapped to a specific charge, a responsible institutional actor, a timeframe, and an expected outcome (Table ES3).

Table ES3. Reform requires sequenced action across four themes

Charge	Stakeholder	Recommendation	Timeframe
Theme 1: Correct structural tariff distortions CSS and AS exist partly because tariffs are not cost-reflective, and fixed costs are bundled into energy charges. Reforming tariff structures reduces the need for compensatory surcharges.
CSS	SERCs and state governments	Publish a time-bound trajectory for ABR–ACoS alignment across consumer categories. Implement a trajectory to align consumer tariffs within a ±20 per cent band of ACoS, protecting vulnerable consumers through direct budgetary transfers rather than embedded cross-subsidies.	1 year
CSS	SERCs and state governments	Undertake structural tariff reforms to progressively eliminate cross-subsidies from tariff design. Any support for vulnerable consumers should be through direct budgetary transfers, not tariff cross-subsidies, so that CSS becomes redundant.	2–4 years
AS	SERCs	Implement phased tariff rebalancing by progressively increasing fixed charges and reducing energy charges, beginning with C&I categories. Introduce sunset provisions for AS in states where rebalancing substantially improves fixed-cost recovery.	2–4 years
Banking	MoP and SERCs	The current 8% cap incentivises volume restrictions rather than cost-reflective pricing. Revise the GEOA Rules 2022 to allow for cost-reflective floor and ceiling anchored to independently estimated injection–withdrawal mismatch costs.	2–4 years
Theme 2: Build the transparency and evidence base Accurate charges require data that does not yet exist in most states. These actions establish the foundation on which all subsequent reforms depend.
AS	Discoms and SERCs	Publish quarterly, block-wise data on stranded capacity, OA drawal volumes, curtailment events, and scheduling deviations. Data must be publicly available on discom and SERC websites.	1 year
Standby	Discoms	Publish quarterly data on standby capacity contracted, standby power drawn, and associated revenues.	1 year
AS	SERCs	Require discoms to demonstrate a direct link between OA transactions and specific stranded capacity before levying AS. Exclude curtailment arising from demand-forecasting errors or avoidable RE backdown.	1 year

Charge	Stakeholder	Recommendation	Timeframe
Theme 2: Build the transparency and evidence base Accurate charges require data that does not yet exist in most states. These actions establish the foundation on which all subsequent reforms depend.
Banking	SERCs and discoms	Commission independent studies to quantify the actual system costs of banking, including discom back-down costs and peak procurement premiums. Conduct a structured stakeholder consultation before revising banking provisions.	1 year
POC	SERCs, SLDCs, and discoms	Commission large-sample harmonic studies stratified by fuel type. Publish results and make them available for public comment before use in charge-setting.	1 year
Wheeling	Discoms	Leverage RDSS to prioritise feeder- and distribution-transformer-level metering, enabling voltage-wise loss assessment and network-cost segregation.	1 year
Theme 3: Align charges with actual costs Most charges are set using outdated proxies or methodologies that no longer reflect the costs they are meant to recover. These actions correct the design
CSS	MoP and SERCs	Review the CSS methodology and notify of a revised methodology after consultation with the states. Align CSS computation with the actual cross-subsidy embedded in consumer tariffs rather than the ACoS– VCoS divergence.	1 year
Standby	SERCs and discoms	Mandate two-part standby tariffs separating capacity reservation from energy components. Require mandatory standby commitment agreements for all consumers above a threshold load, drawing on Maharashtra’s four-tier framework.	1 year

Charge	Stakeholder	Recommendation	Timeframe
Theme 4: Strengthen market mechanisms and planning Administrative charges are a second-best substitute for market signals. These actions build the systems that can replace them over time.
Standby	SERCs and discoms	Integrate standby commitments into resource adequacy assessments and power-procurement planning. Contracted standby capacity should be treated as a known load to reduce the risk of stranded capacity.	2–4 years
Standby	CERC, SERCs, and market institutions	Enable standby services to be procured through ancillary services and balancing markets, allowing reserve capacity to be sourced competitively rather than through administrative tariffs.	2–4 years
Banking	SERCs and discoms	Develop regulatory frameworks and technical standards for gridconnected BESSs for C&I consumers, covering grid connectivity, scheduling protocols, and metering.	1 year
Banking	SERCs and discoms	Develop a transition pathway from banking-dependent RE procurement to market-based balancing, integrating access to the day-ahead market (DAM) or real-time market (RTM) for C&I consumers and hybrid procurement structures. Publish state-level timelines so C&I consumers can plan contract structures accordingly.	2–4 years

Source: Authors’ analysis

FAQs

What are open access charges, and why do they exist?

When C&I consumers buy electricity from the discom, the tariff they pay covers not just the cost of power but also network maintenance, cross-subsidy for agricultural and domestic consumers, backup capacity, and grid balancing. When these consumers switch to open access and buy power directly from a renewable energy generator, the discom needs to be compensated for some revenue loss (cross-subsidy, and stranded power purchase cost) and services such as grid balancing, backup arrangements. Open access charges compensate discoms for these continuing costs. Six charges apply: cross-subsidy surcharge (CSS), additional surcharge (AS), standby charge, banking charge, parallel operation charge (POC), and wheeling charge.
What is energy banking, and why does it matter for renewable energy?

Solar power generates most electricity during midday hours, but consumers need power throughout the day, including evenings. Banking allows RE generators to inject surplus power into the grid during the day and withdraw an equivalent amount later. The discom effectively acts as a virtual grid battery. This service has a cost: the discom backs down thermal generation during injection (while still paying fixed charges to generators) and procures replacement power from the market during peak withdrawal hours. Banking charges are meant to recover these costs, but most states either cap the charge or restrict banking volumes rather than pricing the service to reflect actual costs.
Why are tariff reforms and open access charges linked?

Several open access charges exist because underlying tariffs are not cost-reflective, and different reforms affect different charges. CSS exists because C&I tariffs exceed the average cost of supply; as states align the two, the cross-subsidy shrinks, and CSS should fall. AS exists because discoms recover most fixed costs through energy charges; if tariffs were rebalanced toward higher fixed charges, discoms would recover these costs regardless of migration, making AS redundant. Banking charges arise from the mismatch between RE generation and consumption timing; as time-of-day tariffs mature, consumers face signals to align consumption with generation, reducing banking volumes and associated costs. In each case, the open access charge is a symptom of a tariff design problem, not a solution to it.
What is driving C&I consumers to procure renewable energy beyond cost savings?

Several regulatory and market forces are converging. The EU’s Carbon Border Adjustment Mechanism will impose costs on carbon-intensive exports of steel, cement, aluminium, and fertilisers. SEBI’s BRSR framework makes emissions disclosure mandatory for top-listed companies. The GHG Protocol Scope 2 revision proposes hourly matching for reporting, which means companies will need to demonstrate clean energy procurement at a granular level. Sustainability-linked loans tie borrowing costs to emission reduction targets. And multinational supply-chain mandates, such as Apple’s commitment to a 100 per cent carbon-neutral supply chain, require verified renewable procurement from Indian suppliers. Together, these pressures are transforming RE procurement from a cost-driven choice into a compliance and competitiveness requirement.