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Power and Carbon MarketsIndia’s Green Energy Open Access Rules: How Industrial Consumers Procure Renewable Electricity and Why the Route Chosen Determines CCTS, CBAM and RCO Compliance Simultaneously
The Electricity (Promoting Renewable Energy Through Green Energy Open Access) Rules, 2022 — notified on 6 June 2022 and amended twice in 2023 — are the operational backbone of India’s industrial renewable energy transition. They govern how a steel mill, an aluminium smelter, a cement plant, a fertiliser manufacturer or a chemical complex can procure solar or wind electricity outside the state DISCOM’s supply, and what charges apply when they do. The route a consumer chooses — third-party open access, captive, or group captive — determines not just the cost of the power but also whether the Cross-Subsidy Surcharge and Additional Surcharge are waived, whether the electricity counts toward RCO compliance, whether it reduces CCTS Scope 2 GEI, and whether it reduces CBAM embedded emissions. These are four separate regulatory consequences of a single procurement decision, and understanding them in detail is the difference between a compliance strategy that works and one that satisfies one requirement while failing two others.
The GEOA Rules reduced the minimum contracted demand for green energy open access from 1 MW to 100 kW, opened the route to demand aggregation across multiple connections in the same operating area (January 2023 amendment), and created a single-window application portal through the Green Open Access Registry. As of November 2024, 28 of 29 Indian states have adopted the GEOA framework in some form; Kerala is the only state without GEOA provisions. The C&I open access market grew at 46% CAGR from FY2022 to FY2024, reaching a cumulative installed capacity of 18.7 GW. Annual additions are forecast to exceed 6 GW in FY2025.
Three procurement routes exist under GEOA. Third-party open access — buying power from an unrelated RE developer — carries the full charge stack: transmission or wheeling, Cross-Subsidy Surcharge, Additional Surcharge, banking charges and standby charges. Captive open access — where the consumer owns at least 26% equity in the generating plant and consumes at least 51% of its output — waives CSS and AS, which are the two largest discretionary charges, reducing landed cost materially in high-surcharge states like Maharashtra. Group captive applies the same waiver logic to consortia of consumers who collectively meet the 26%/51% conditions. For industrial decarbonisation at scale, captive and group captive are the structurally preferred routes.
The choice of procurement route has four simultaneous regulatory consequences: (1) on RCO compliance — all three routes satisfy the Renewable Consumption Obligation with physical RE, whereas RECs do not; (2) on CCTS Scope 2 GEI — all three routes reduce the Scope 2 component of GEI because the electricity consumed is counted at zero emission factor, whereas grid electricity attracts the CEA grid emission factor of 0.710 tCO₂/MWh; (3) on CBAM embedded emissions — physical RE procurement reduces Scope 2 embedded emissions directly, creating reduced CBAM certificate cost for EU exporters; (4) on CSS/AS liability — only captive and group captive routes waive CSS and AS, while third-party procurement pays them unless the specific state has waived them.
The ISTS waiver — which eliminated inter-state transmission charges for RE projects, making it economically viable for a steel mill in Maharashtra to source solar power from Rajasthan — ended at full value (100%) for projects commissioned after 30 June 2025. The phase-out is: 75% waiver for projects commissioned by June 2026, 50% by June 2027, 25% by June 2028, and zero thereafter. This adds approximately Rs 0.40 to Rs 0.50 per kWh to landed costs for new ISTS-sourced open access projects. Projects targeting offshore wind, green hydrogen production, and pumped hydro retain full waivers beyond these deadlines. Around 26 GW of projects were at risk from the waiver expiry according to CRISIL (July 2025).
The key protective provision in GEOA for industrial RE buyers is the CSS cap: the Cross-Subsidy Surcharge cannot increase by more than 50% of the initial year’s CSS during the first 12 years of a plant’s operation. This prevents DISCOMs from using CSS escalation to claw back the economics of long-term RE open access agreements signed in good faith. The cap is a central regulatory protection; without it, the landed cost of open access RE could be eroded by DISCOM regulatory action at the state level. The cap applies only to third-party consumers — captive and group captive consumers are exempt from CSS entirely.
The three procurement routes — what each means structurally
The GEOA Rules create three distinct legal and commercial structures for industrial RE procurement. They share the same physical infrastructure — the state and inter-state transmission grid — but carry different charge profiles, different ownership obligations, and different regulatory protections. The choice between them is not merely a procurement decision; it is a structural decision that shapes an entity’s regulatory position across the RCO, CCTS, and CBAM frameworks simultaneously.
The contrast in cost structure between third-party and captive routes is most acute in states with high Cross-Subsidy Surcharges. In Maharashtra, the CSS at MSEDCL has historically been approximately Rs 2.23 per kWh — added to the PPA tariff, wheeling charge and banking charge, this can bring the landed cost of third-party open access solar to Rs 8 to 10 per kWh, compared with a DISCOM industrial tariff of Rs 8.50 to Rs 13 per kWh. The economics are marginal to favourable at best. A captive consumer in Maharashtra, by eliminating the Rs 2.23 CSS, brings the landed cost to Rs 5.50 to 7 per kWh — a far more compelling comparison against the DISCOM tariff. This is why captive and group captive structures dominate in high-surcharge states, and why CSS waiver is the single largest financial driver of RE procurement decisions by heavy industrial consumers.
In Odisha and Chhattisgarh — where both CSS and AS have been completely waived for solar and wind regardless of the procurement category — even third-party open access delivers landed costs of Rs 4.30 to 5.00 per kWh, which is already below the coal CPP generation cost for many aluminium smelters and makes the open access route commercially self-justifying without the captive CSS waiver. This is a direct regulatory explanation for why Odisha and Chhattisgarh together account for the majority of demand in the captive power consumer open access category — the aluminium smelters in these states have the lowest absolute open access cost of any state in India, and the regulatory environment most conducive to scaling RE procurement quickly.
The full charge stack — what an industrial consumer actually pays
The landed cost of open access RE is not the PPA tariff. It is the PPA tariff plus a set of charges that varies by state, by procurement route, and by the consumer’s connection voltage and category. Understanding the full charge stack is essential before any comparison with DISCOM tariffs or with captive coal power costs.
| Charge | What it covers | Third-party | Captive / Group captive | Key GEOA provision |
|---|---|---|---|---|
| PPA tariff | Power purchase price agreed with generator | Rs 2.50–3.50/kWh (solar, 2025) | Rs 2.50–3.50/kWh (solar, 2025) | Market-determined; subject to ALCM/DCR module cost pressures post-June 2026 |
| Wheeling / transmission charges | Payment to DISCOM/STU for use of their wires | Payable — Rs 0.50–1.50/kWh (state-specific) | Payable — same rate as third-party | Set by SERC in tariff order; GEOA does not waive this charge |
| Cross-Subsidy Surcharge (CSS) | Compensates DISCOM for revenue loss when large consumers exit their supply | Payable — capped at +50% over 12 years | Fully waived — SC 2021 confirmed | CSS cannot increase more than 50% of initial year rate over first 12 years of plant (third-party only). Odisha/CG waive CSS entirely for all categories |
| Additional Surcharge (AS) | Covers DISCOM’s fixed costs of obligation to supply when consumer goes to open access | Payable if consumer not paying fixed charges | Fully waived — captive users exempt | AS not applicable if consumer pays fixed demand charges to DISCOM; SC 2021 confirmed captive users exempt. Green H₂/ammonia: AS also waived in third-party |
| Banking charges | Fee for “storing” excess generation in the grid for later drawdown | 2–8% of banked energy (state-specific) | 2–8% of banked energy (state-specific) | Monthly banking standardised; unused banked energy lapses at end of banking cycle; generator gets RECs for lapsed energy |
| Standby charges | Payment to DISCOM for providing backup when RE plant is unavailable | Generally 120% of standard tariff (Andhra Pradesh model); varies by state | Applicable during plant outages; a key operational cost factor | GEOA requires this charge to be specified upfront for certainty; rate capped at standard tariff in many states |
| ISTS charges (for inter-state RE) | Payment for use of national transmission network | Currently 25% of full rate for projects commissioned Jul 2025–Jun 2026 | Same schedule — captive does not waive ISTS charges | Phase-down schedule: 25% → 50% → 75% → 100% of full ISTS charge by 2028. Offshore wind, green H₂, PSP: different waiver schedules |
| LDC / scheduling charges | State Load Despatch Centre fees and injection/drawdown scheduling | Rs 0.02–0.10/kWh (minor, varies) | Same | Minor charge; GEOA requires upfront disclosure |
Working through a representative example: an aluminium smelter in Odisha procuring third-party solar open access in April 2026, from a plant commissioned in July 2025, would face: PPA tariff at approximately Rs 3.10 per kWh; intra-state wheeling at approximately Rs 0.90 per kWh; CSS waived (Odisha state policy); AS waived (Odisha state policy); banking charges at approximately 5% of banked energy (assumed 10% of monthly consumption banked = Rs 0.16/kWh equivalent); ISTS charges at 25% of full rate (plant commissioned in the waiver phase-down period) at approximately Rs 0.25/kWh; scheduling fees at Rs 0.05/kWh. Total landed cost: approximately Rs 4.46 per kWh. This compares favourably with coal CPP generation at Rs 5.00 to 5.50 per kWh before the CCTS and CBAM value layers are added.
The ISTS waiver phase-out — the most consequential cost change since GEOA was notified
The Inter-State Transmission System charge waiver was the policy mechanism that made it economically viable for industrial consumers to procure solar power from resource-rich states — Rajasthan and Gujarat, which together account for over 70% of recent C&I open access installations — and deliver it to manufacturing facilities in Maharashtra, Uttar Pradesh, Odisha, Chhattisgarh, and Madhya Pradesh. At its peak, the waiver saved industrial consumers approximately Rs 0.70 to Rs 0.80 per kWh on inter-state RE procurement, making ISTS-sourced solar significantly cheaper than intra-state sources in many high-demand states.
The 100% waiver for solar and wind projects expired on 30 June 2025. CRISIL estimated that approximately 26 GW of RE projects were exposed to the waiver expiry at the time of transition. The phase-out schedule that follows is graduated rather than cliff-edged:
The extended full waivers for offshore wind, green hydrogen and pumped hydro are the most significant policy signals in the post-June 2025 ISTS landscape. They indicate where India’s industrial energy policy is directing investment: firming technologies (PSP), the RE source that can provide 24/7 carbon-free power for industrial baseload (offshore wind), and the industrial decarbonisation feedstock of the next decade (green H₂ and green NH₃). Industrial consumers planning inter-state RE procurement after June 2025 should structure their contracts around intra-state generation where possible — where the RE generator and the consuming plant are in the same state, intra-state transmission charges apply but not ISTS charges, and the waiver phase-out is irrelevant.
Four regulatory consequences of one procurement decision
The three-column comparison crystallises the strategic choice. For an aluminium smelter exporting to the EU, the full value stack of physical RE procurement — RCO satisfied, CCTS GEI reduced (CCC revenue), CBAM Scope 2 reduced (certificate cost avoided) — is approximately Rs 7.88 per kWh of coal power replaced, against a landed RE cost of Rs 4.30 to 5.50 per kWh. The net return is positive before electricity cost savings are considered. RECs, which cost Rs 1,500 to 2,500 per MWh on the exchange, satisfy only the RCO. They deliver none of the CCTS or CBAM value. The procurement route is not a compliance question; it is a capital allocation question with a clear quantified answer.
DISCOM resistance — the structural obstacle that cannot be regulated away
The GEOA framework is well-designed on paper. Its challenges are primarily at implementation, driven by a structural tension that no regulation can fully resolve: DISCOMs lose revenue when large industrial consumers migrate to RE open access, and those consumers were cross-subsidising lower-income and agricultural users through their DISCOM tariffs. Ember estimates that if 50% of C&I consumers shift to RE procurement through open access, the average loss gap for DISCOMs would increase by 53% per unit of electricity under third-party models and 100% under captive models. This is not a trivial financial stress — it threatens the financial viability of already-indebted state DISCOMs and creates genuine political pressure on state governments that are simultaneously trying to expand DISCOM service and reduce consumer tariffs.
The manifestations of DISCOM resistance are operational rather than regulatory: applications that exceed the 15-day approval deadline without action; state-level surcharge increases that approach or test the CSS cap; SLDC-DISCOM coordination breakdowns that delay open access scheduling; banking settlement disputes that tie up consumer funds; and lobbying by DISCOMs for state-level regulations that deviate from central GEOA provisions. Tamil Nadu, Karnataka, and Uttar Pradesh do not follow the central 100 kW eligibility threshold; Karnataka’s cross-subsidy charges jumped 240% in Q2 2025, triggering sharp increases in open access landed costs in that quarter.
The GEOA Rules provide a partial answer: the CSS cap prevents the most egregious DISCOM behaviour, and the central rules take precedence over inconsistent state regulations under the Electricity Act 2003’s Section 176 framework. But the implementation realities mean that an industrial consumer entering the GEOA market for the first time should anticipate: approval timelines of 30 to 60 days rather than the mandated 15 days in many states; the need for legal assistance in states where DISCOM resistance is documented; and ongoing monitoring of state SERC orders for CSS rate adjustments that approach the cap.
The Approved List of Models and Manufacturers requirement — extending to solar modules from June 2026 — is expected to affect 20 to 25 GW of green open access projects that planned to use cheaper imported modules not on the ALMM list. PPA tariffs have already risen by approximately Rs 0.25 per kWh in Q4 2025 in anticipation of the ALCM compliance deadline, as developers priced in higher domestic module procurement costs. Aluminium smelters and steel mills that signed open access solar PPAs in 2024 or early 2025 are partially insulated if their plants commissioned before June 2026. Those commissioning after that date face the full ALCM-driven cost increase. The ISTS tariff phasedown and the ALCM cost increase are arriving simultaneously, creating a window in 2026 to 2028 where new open access solar’s landed cost is higher than in 2023 to 2024 — narrowing but not eliminating the cost advantage over coal CPPs and DISCOM supply. The CCTS and CBAM value streams, which have increased significantly since 2024, more than offset this headwind for export-oriented industrial consumers.
Frequently Asked Questions
What is the difference between a captive and a group captive structure under GEOA?
A captive generating plant is one owned by a single consumer (or its holding/subsidiary, under the September 2023 amendment to the Electricity Rules) who consumes at least 51% of its generation annually and holds at least 26% of its equity. A group captive structure allows multiple consumers to collectively satisfy the 26% equity and 51% consumption conditions. In a group captive typically structured through a Special Purpose Vehicle, each participating consumer holds a proportionate share of the SPV’s equity and must consume electricity in proportion to that shareholding, within a 10% annual variation. The Group Captive Rule of Proportionality is strictly enforced: if any member fails to consume its proportionate share in a given year — due to a production outage, for example — the electricity it failed to consume may be classified as non-captive, potentially triggering CSS liability for all members. This makes group captive structures more complex to manage operationally than single-consumer captive projects, but the CSS and AS waiver benefit is identical.
Can a consumer simultaneously procure GEOA electricity and buy RECs for the same purpose?
Functionally, yes — but it would be redundant and potentially costly without purpose. RECs satisfy the Renewable Purchase Obligation and Renewable Consumption Obligation. Physical RE through GEOA also satisfies the RCO (since it provides physical renewable electricity) and additionally reduces CCTS Scope 2 GEI and CBAM embedded emissions. A consumer who procures physical RE through GEOA has already satisfied its RCO obligation for that unit of electricity and has no need to buy RECs on top. Buying RECs while also procuring GEOA RE for the same consumption volume is an unnecessary additional expense. The important distinction is the reverse: a consumer who buys RECs without procuring physical RE through GEOA has satisfied the RCO but has not reduced its CCTS GEI or CBAM embedded emissions — the underlying electricity at the plant is still grid-sourced at the grid emission factor.
How does the 15-day approval deadline under GEOA work in practice?
The GEOA Rules mandate that open access applications must be disposed of within 15 days of receipt. In practice, this deadline is frequently exceeded. The Green Open Access Registry portal, which serves as the single-window application platform, has documented coordination failures between State Load Despatch Centres and DISCOMs that result in processing delays. Applications may sit with the SLDC for weeks without DISCOM acknowledgement, or vice versa. Consumers who face repeated delays beyond the 15-day mandate can raise complaints with the State Electricity Regulatory Commission, and the central GEOA Rules take precedence over DISCOM procedural resistance under the Electricity Act 2003. However, the practical resolution process through the SERC typically adds weeks to months beyond the original timeline. Industrial consumers entering the open access market for the first time should build 30 to 60 days of buffer into their procurement timeline in states with documented DISCOM resistance, including Maharashtra, Tamil Nadu and Karnataka.
What happens to banked energy that is not consumed within the monthly banking cycle?
Under the GEOA framework, monthly banking is the standard period. Any surplus generated energy that was banked but not consumed within the same month lapses at the end of that monthly billing cycle — the consumer loses that energy credit. However, as a consolation, the generator is entitled to receive Renewable Energy Certificates to the extent of the energy that lapsed without consumption. The banking charge (typically 2 to 8% of banked energy, depending on the state SERC order) is still payable on the banked energy even if it lapses. This creates an incentive for consumers to accurately forecast their energy consumption relative to generation output and minimise unnecessary banking. For aluminium smelters and other baseload industrial consumers with highly predictable electricity demand, banking lapse risk is low — but for industrial consumers with variable production schedules, over-procurement leading to banking lapse is a real cost.