For most factories, rooftop solar is the best first tranche when the site has usable roof area, a steady daytime load and limited tolerance for regulatory complexity. Group-captive solar is more suitable when the roof cannot host enough capacity and the buyer can commit capital or ownership for a remote plant. Third-party green open access preserves capital and flexibility, but its delivered cost depends on state-specific transmission, wheeling, losses, banking, cross-subsidy, standby and other charges.
The three power models at a glance
A factory can obtain solar electricity in three fundamentally different ways. It can generate behind its own meter on the factory roof, participate as an owner or qualifying consumer in a shared remote plant, or buy power from a developer through green open access. The right choice follows the plant’s load curve, roof and lease conditions, credit capacity, appetite for long-term commitments and the rules in its state and distribution area.
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| Decision axis | Rooftop solar | Group-captive solar | Third-party green open access |
|---|---|---|---|
| Generation location | Factory roof or adjacent premises | Usually a remote, shared plant | Usually a remote developer-owned plant |
| Grid-delivery exposure | Lower for on-site self-consumption; export and net- or gross-metering rules still apply | High: wheeling, transmission, banking and scheduling are relevant | High: wheeling, transmission, banking, scheduling and surcharges are relevant |
| Upfront capital | High under CAPEX; lower under RESCO/OPEX | Shared investment or contracted ownership | Low to moderate, depending on the PPA and security package |
| Best fit | Daytime load and usable roof | Roof-constrained sites able to make a long-term commitment | Capital-light procurement by a creditworthy buyer |
| Primary diligence | Roof condition, structural loading, interconnection and demand profile | Captive qualification, ownership, consumption, land, evacuation and governance | State eligibility, charges, banking, contract tenor, forecasting and settlement |
When rooftop solar should come first
Match generation to the factory’s daytime demand
Rooftop PV is simplest when the factory consumes electricity during daylight hours. Energy is produced at the same premises, so the plant can use a large share without paying remote-network wheeling and transmission charges. The correct sizing exercise starts with interval demand, not the maximum roof area. Size against the site’s daytime minimum and normal operating profile, then test weekends, holidays, shutdowns and seasonal production.
Oversizing can create exports that are paid or credited under state rules, or may be curtailed if export capacity is limited. The commercial result therefore depends on the applicable net-metering, gross-metering or other export arrangement. Obtain the current rule from the state electricity regulatory commission and the distribution company before fixing the system size.
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Check whether the roof can safely host the array
An engineering survey should verify structural capacity, roof age, waterproofing, corrosion, wind exposure, drainage, fire access, maintenance walkways and shading from sheds, stacks or future buildings. A leased factory needs enough remaining term to recover the investment, or a clear right to remove or transfer the system. The interconnection study must confirm the point of coupling, protection, metering, sanctioned demand and any export limit.
Choose the ownership model
Under CAPEX, the factory buys the PV system and carries performance, maintenance and replacement obligations, while retaining the energy savings. A RESCO or OPEX arrangement reduces upfront spending: a service provider owns and operates the system and sells or services the electricity under a contract. Compare both structures after taxes, escalation, insurance, roof work, inverter replacement and contract-end removal obligations. A low headline energy price is not enough if the agreement leaves the factory with roof-repair or underperformance risk.
When group-captive solar is the better fit
Use a remote plant when the roof is the constraint
Group-captive projects let several consumers share a larger solar plant, commonly on land with better solar yield and easier expansion than an industrial roof. They can provide a substantial renewable supply where on-site space is inadequate. The trade-off is that every unit of energy must be scheduled and delivered through the grid, exposing the project to transmission, wheeling, losses, banking and settlement rules.
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Prove captive status before signing
Group-captive treatment depends on continuing compliance with the applicable ownership and consumption requirements. The factory should document its equity or ownership rights, voting and governance arrangements, contractual allocation, metering and the required share of consumption. The diligence model must show what happens if production falls, ownership changes, a participant exits or the project misses a qualification test. Losing captive status can change the charges applied to delivered power and undermine the financial case.
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Do not rely on a developer’s generic national summary. The Ministry of Power states that Green Energy Open Access Rules, 2022 reduced the open-access eligibility threshold from 1 MW to 100 kW and that there is no limit for captive consumers. MNRE’s rule index records the 2022 rules and 2023 amendments, including eligibility and banking provisions. The exact application still depends on the current state framework, metering and approvals.
Assess land, evacuation and governance risk
For a remote project, inspect land rights, permits, construction status, evacuation capacity, substation availability, commissioning schedule and curtailment provisions. The participation agreement should define voting, budget approvals, operation and maintenance standards, insurance, lender rights, transfer restrictions, default remedies and the process for replacing a participant. A technically sound plant can still fail commercially if governance prevents timely decisions or if evacuation is delayed.
When third-party green open access makes sense
Preserve capital and procurement flexibility
A third-party developer can build and own the solar plant while the factory buys electricity under a power-purchase agreement. This approach is attractive to a factory that wants renewable supply without funding all construction, or that prefers to diversify among projects. The buyer’s credit quality, payment security, tenor, termination rights and minimum-take obligations will influence the price.
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Model the delivered unit cost as the contracted energy price plus transmission, wheeling, transmission and distribution losses, cross-subsidy surcharge, additional surcharge where applicable, banking, standby, scheduling, forecasting and deviation-settlement costs. Include taxes, duties, meter charges, administration fees, curtailment treatment and any replacement energy when solar output is below forecast. Compare that total with the factory’s avoidable grid cost, not merely its average tariff.
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Charges and banking rules can vary by state, voltage level, consumer category and regulatory order. CERC’s current-regulations page shows amendments and proceedings continuing through 2025–2026, so a financial model should use written, current schedules rather than an old consultant presentation. Build sensitivities for tariff changes, solar yield, loss factors, banking limits, surcharge changes, delays and deviation costs.
A decision process that produces a bankable answer
- Assemble operating data. Collect 12–24 months of interval load data, sanctioned demand, tariff components, maximum demand, production calendars, outage history and any existing generator or renewable contracts. Separate daytime baseload from shift, seasonal and shutdown consumption.
- Survey the premises. Measure usable roof area and shading; inspect structure, fire access, drainage, waterproofing and lease term. Record the electrical single-line diagram, transformer capacity, protection settings, meter location and available interconnection capacity.
- Size a rooftop tranche. Model PV output against the daytime minimum and normal load. Test export limits, curtailment and the state’s net-metering or gross-metering treatment. If exports dominate the result, reduce the system or evaluate storage only after confirming its cost and operating value.
- Screen remote options. For group captive and third-party open access, obtain the plant’s location, injection and drawal points, voltage level, scheduled capacity, loss factors, banking terms and all current charges. Ask who bears forecasting, deviation and standby liabilities.
- Test group-captive compliance. Have counsel and the technical team map ownership, consumption, metering, voting, allocation and exit provisions to the current rules. Quantify the financial consequence of falling out of captive status for one month, one quarter and the remaining contract term.
- Compare financing structures. Evaluate rooftop CAPEX, rooftop RESCO/OPEX, group-captive participation and third-party PPA on an after-tax, after-escalation basis. Include insurance, operations, roof restoration, inverter replacement, security deposits, termination payments and residual value.
- Obtain written approvals. Confirm the current position with the state electricity regulatory commission, state load dispatch centre and DISCOM before execution. Keep the applicable orders, charge schedules, connectivity approvals and meter specifications with the contract file.
Technical and commercial requirements by model
Rooftop checklist
- Structural certificate for dead load, wind load and mounting method.
- Roof warranty and waterproofing responsibility during and after installation.
- Protection, anti-islanding, synchronization, meter and grid-code compliance.
- Defined treatment of exports, curtailment, outages and planned maintenance.
- Operations access, cleaning water, fire lanes and safe isolation procedures.
Group-captive checklist
- Documented ownership and consumption rights that remain valid throughout the supply period.
- Land title or lease, permits, evacuation approval and transmission availability.
- Metering architecture linking generation, allocation and each drawal point.
- Governance rules for budgets, outages, refinancing, transfers and participant default.
- Clear remedy if a participant no longer meets captive conditions.
Third-party open-access checklist
- Eligibility confirmation for the factory’s category, contract demand and voltage level.
- Itemised transmission, wheeling, loss, surcharge, banking, standby and scheduling charges.
- Forecasting, deviation settlement, curtailment and replacement-power provisions.
- Credit support, payment security, change-in-law, termination and dispute clauses.
- Evidence that the developer can obtain connectivity and maintain the required approvals.
How national policy fits the project
MNRE’s Grid Connected Rooftop Solar Programme states an objective of 40,000 MW of cumulative grid-connected rooftop capacity and lists Phase II as running until 31 March 2026. That national programme objective does not establish a uniform commercial-factory incentive or guarantee a particular state export arrangement. Check the current state and DISCOM provisions for the actual site.
For larger procurement, MNRE lists Guidelines for Tariff Based Competitive Bidding Process for Procurement of Power from Grid Connected Solar PV Power Projects dated 2 February 2024. Those guidelines can inform procurement design, but a factory still needs a project-specific contract, interconnection approval and state-level charge analysis.
Illustrative choices for common factory situations
Large roof, two-shift production and a short decision horizon
Prioritise a rooftop tranche sized to self-consumption. A CAPEX or RESCO structure can be compared quickly because generation and load are co-located. Keep a remote option as a second phase if the roof cannot cover the long-term renewable target.
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Small or heavily obstructed roof with stable credit
Screen a third-party open-access PPA first, then compare it with a group-captive stake. The PPA may require less capital and governance, while group captive may offer a different long-term cost profile but requires continuing compliance and ownership participation.
Several plants under one corporate group
Map each site’s load, voltage, DISCOM and state rules separately. A shared remote project may work only for sites that can legally and physically receive the scheduled energy; do not assume one approval or one banking treatment covers every location.
Common failure modes and fixes
- Using the generation tariff as the delivered price: rebuild the model with every network, surcharge, banking, standby and deviation component.
- Installing to roof capacity rather than load: re-size against interval demand and verify export limits before ordering equipment.
- Assuming national rules override state orders: obtain written, current positions from the SERC, SLDC and DISCOM.
- Treating captive status as permanent: monitor ownership, consumption and metering continuously and model the cost of non-compliance.
- Ignoring physical constraints: complete structural, fire, evacuation and protection studies before financial close.
- Accepting an inflexible contract: negotiate change-in-law, curtailment, delay, underperformance, transfer and termination remedies.
Bottom line for a factory decision
Start with rooftop solar when the site has a sound roof, meaningful daytime consumption and a need for a straightforward first project. Move to group captive when roof constraints justify a larger remote plant and the factory can accept ownership, consumption and governance obligations. Choose third-party green open access when preserving capital and procurement flexibility matters more than eliminating grid-delivery complexity. In every case, approve the investment only after the state-specific delivered-cost model, current charges and written approvals are complete.
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