Financing India's Energy Transition: How Project Finance Is Moving Beyond The Solar And Wind Playbook

I. Introduction

For much of the last decade, financing an Indian renewable energy project usually meant financing a familiar solar or wind template: a long-term power purchase agreement, a tariff discovered through bidding or assessed against the applicable CERC framework, and payments linked to power actually supplied². This template was typically backed by a letter of credit, mortgage and hypothecation package. It still matters, but it does not fully answer the lenders’ questions for newer asset class such as battery energy storage systems (“BESS”), green hydrogen and firm and dispatchable renewable energy (“FDRE”). Each has a different payment logic from the simple “rupees per unit generated” model. These models range from availability-based capacity payments to production-linked subsidies, requiring lenders to revisit cash flows, subsidy eligibility, security packages, step-in rights, enforcement risk and the allocation of risk between the developer, the offtaker and the government.

This article explores each of the three asset classes against the same five variables, focusing on the revenue model, bankability, security package, risk allocation, and financing structure.

II. The Baseline: What Solar and Wind Financing Still Looks Like

Under the conventional model, developers sign long-term PPAs with tariffs discovered through competitive bidding and adopted under Section 63 of the Electricity Act, 2003. Lenders mainly focus on resource risk and offtaker credit risk. The usual security package includes mortgage over project land, hypothecation over plant and machinery, pledge of promoter/sponsor shares and a debt service reserve. This works because the cash-flow stream is fairly predictable. The newer asset classes discussed below depart from this baseline.

III. Battery Energy Storage Systems (BESS)

Revenue model and bankability

BESS revenue is not a simple per-unit tariff. The Union Cabinet’s Viability Gap Funding (“VGF”) Scheme provides capital support of up to forty per cent of project cost for an initial 4,000 MWh, with disbursement linked to specified milestones.³ The VGF is not operating revenue. It reduces the equity and capex burden and therefore affects debt sizing. Separately, the developer earns an availability-based payment under a Battery Energy Storage Purchase Agreement (“BESPA”), rather than payment only for energy sold. In simple terms, solar and wind projects are paid for generation; BESS projects are paid largely for availability. Since BESS lacks the multi-decade operating history of solar and wind, and battery degradation directly affects revenue capacity over the debt tenor, lenders face technology risk that is still relatively new in the Indian market. A useful bankability reference is SECI’s 500 MW/1,000 MWh BESS tender, where CERC declined to adopt the discovered tariff because, on the facts of that case, it no longer reflected prevailing market conditions.⁴This has become a useful reference point for why BESS bankability cannot simply be read off the VGF subsidy percentage and why the underlying tariff discovered at auction still has to clear CERC’s own reasonableness test before debt can be drawn.

Security package and risk allocation

“Energy Storage System” has been added to the Harmonised Master List of Infrastructure Sub-Sectors⁵, supporting access to infrastructure financing channels, including longer-tenor debt and certain ECB or institutional capital structures, subject to applicable eligibility conditions.

Beyond this broader access to capital, the VGF-linked revenue stream also shapes the specific security package lenders will require. Because VGF tranches are themselves a contractual entitlement payable on defined milestones, sponsors and lenders increasingly negotiate an assignment of / charge over the VGF receivables into the security package. Lender diligence should therefore cover the scheme conditions precedent, domestic-content compliance, notice and acknowledgement mechanics for the receivables’ assignment, and whether loss of VGF eligibility triggers sponsor support. Further, the VGF scheme’s domestic-content conditions, including a minimum twenty per cent local-content requirement and a mandatory indigenously developed Energy Management System⁶, effectively transfer manufacturing and technology-sourcing risk to the developer in exchange for subsidy eligibility. Because the developer must meet these domestic-sourcing conditions to unlock the subsidy, the developer - not the government or the lenders - bears the risk if compliant local equipment or an indigenous EMS is unavailable, more expensive, underperforms, or delays the project.

Financing structure

BESS projects in India are commonly structured around a BESPA-linked revenue stream, with government VGF reducing the sponsor’s equity and overall capital burden.  The original BESS VGF scheme targeted the development of 4,000 MWh of BESS capacity by 2030-31. While the total projected outlay for this scheme was ₹9,400 crore, the direct budgetary support from the government was limited to ₹3,760 crore. Separately, in June 2025, the government approved another VGF scheme for 30 GWh of BESS capacity, involving ₹5,400 crore of financial support from the Power System Development Fund⁷. This makes BESS financing a form of public-private blended finance, not simply a private project-finance debt stack.⁸

IV. Green Hydrogen

Revenue model and bankability

Green hydrogen in India does not yet have a settled CERC-style tariff framework. Project economics are instead driven by SIGHT⁹ incentives under the National Green Hydrogen Mission¹⁰, together with negotiated offtake contracts with industrial buyers in sectors such as fertiliser, steel and refining.

Without a tariff anchor, lenders have to diligence technology risk, including electrolyser performance and supply-chain dependence, as well as offtake counterparty risk, since the buyer is usually an industrial purchaser rather than a DISCOM. . The policy framework is also still evolving. Another risk was added when the government issued Revised Scheme Guidelines for green hydrogen pilot projects, providing up to eighty per cent capex support for private entities and full support for government bodies in residential, household and city-gas applications, which is a scheme structure that itself remains subject to revision as the sector matures¹¹.

Security package and risk allocation

Hydrogen projects frequently involve more than one special-purpose vehicle across the value chain, including the renewable-generation SPV, the electrolyser/production SPV, and, where relevant, a derivative (ammonia or methanol) offtake entity, and each may be financed and secured separately. This creates intercreditor and interface risk. Lenders must consider cross-defaults, cash-sweep restrictions, shared security, step-in rights and the consequences of underperformance in one SPV on the rest of the value chain. As on date, eligible green hydrogen and green ammonia production units continue to receive a waiver of inter-state transmission charges for renewable energy used for production, with the full twenty-five-year waiver available for projects commissioned within the current eligibility window and tapering thereafter in accordance with the applicable CERC sharing-regulation framework. This waiver can materially improve project economics and should be reflected carefully in the base case, eligibility conditions and cash-flow waterfall. Because the SIGHT production-linked incentive is paid against actual output rather than capital expenditure, technology and execution risk sits substantially with the developer. This is the opposite of the BESS VGF model, where support is front-loaded against capex milestones rather than linked to subsequent output.

Financing structure

Hydrogen deals are usually financed with a mix of cheaper, development-focused capital alongside regular commercial debt. That is because there is no standard hydrogen offtake or PPA template yet, so lenders have to look closely at each deal's technology, offtake arrangements, pricing, and regulatory risk before committing.

V. Firm and Dispatchable Renewable Energy (FDRE) Projects

Revenue model and bankability

The FDRE Guidelines move away from a pure generation model. They use a demand-following revenue structure measured by the ‘Demand Fulfilment Ratio’, which is scheduled injection divided by the demand specified by the buying entity for the relevant time block¹². In other words, the developer earns more by matching what the buyer actually needs, not by simply generating as much power as possible. There's also a wrinkle around storage: whether the power fed back from storage counts as renewable depends on how it was charged in the first place, so a single project can end up with two different kinds of cash flow - one from contracted supply and one from open-market sales. MNRE has clarified that storage charged from non-RE power is not renewable power, but it may be sold in the open market, merchant or third-party mode without an NOC until the associated RE component is commissioned.¹³ In practice, this means a single FDRE project can end up with two different revenue streams, even though lenders might otherwise expect just one. Because of this, lenders typically discount or leave out the open-market revenue when calculating debt coverage, and track it separately through its own controls.

Security package and risk allocation

FDRE projects are often oversized relative to contracted capacity to satisfy strict delivery profiles, and the Guidelines permit the resulting excess power to be sold to third parties or on power exchanges without requiring the procurer’s no-objection certificate in certain cases.¹⁴ Lenders typically ring-fence the merchant revenue tail within the receivables assignment and security package, either by excluding merchant revenues from base-case debt sizing or by including them in the security package with separate priority, reporting and sweep mechanics. The shortfall risk is largely borne by the developer, making the risk allocation more stringent than in conventional solar or wind PPAs, where shortfalls are often addressed through compensation or other contractual remedies.

Financing structure

FDRE financing also faces regulatory constraints on scale. In recent tariff-adoption proceedings, CERC has treated the use of a greenshoe option in renewable-energy tenders as requiring closer scrutiny because the option is not expressly defined in the Ministry of Power's Section 63 bidding guidelines. CERC has therefore directed renewable energy implementing agencies to seek clarification from the Ministry of Power on the permissibility and contours of the greenshoe mechanism, and has curtailed greenshoe allocations where the allocation pattern raised transparency and equal-treatment concerns. For financing purposes, this means sponsors should not assume that an open-ended greenshoe capacity-expansion structure will be fully bankable unless the tender has a clear regulatory basis and the tariff-adoption risk has been addressed.

VI. Key Learnings and Next Steps

First, the shift from energy-tariff lending to performance-tariff lending is changing the project finance landscape in the renewable energy space. Each asset class discussed above replaces the simple “rupees per unit generated” model with an availability, firmness or capacity-linked metric, such as the Demand Fulfilment Ratio for FDRE, capacity payments for BESS or production-linked incentives for hydrogen. Traditional debt-sizing models do not capture these new risk categories and need to be recalibrated for these risk categories.

Second, the Harmonised Master List and foundational policies like the IREDA Financing Policy for New Technologies serve as unifying financing enablers across these new technologies, expanding the pool of available long-term capital.

Third, regulatory risk is shifting from tariff orders to scheme design. Because VGF and SIGHT incentives are scheme instruments issued by the Ministry of Power or MNRE, rather than CERC tariff orders made under Section 63 of the Electricity Act, sponsors and lenders face a different regulatory-risk profile. Fourth, security packages are no longer template-driven: subsidy receivable assignments, merchant-revenue controls, multi-SPV security and intercreditor arrangements now sit at the centre of lender bankability analysis.

VII. Conclusion

Bankability in India’s energy transition is no longer only about proving that a technology works. It is about allocating performance risk across different revenue streams, security interests and counterparties, often within the same special-purpose vehicle. As BESS VGF support runs up to 2030-31 and SIGHT incentives for green hydrogen phase down toward 2029-30, lenders will need to ask a more practical question: what does debt-service coverage look like once the subsidy window narrows or closes? The next generation of Indian renewable financings will therefore depend not only on the existence of a PPA, but on the quality of the asset-specific risk allocation behind it.

Footnotes

^{1 Acknowledgement: The authors gratefully acknowledge the research and drafting assistance of Vaibhav Kumar (5th year law student at JGLS, Sonepat, Haryana), in preparing this article.}

^{2 Central Electricity Regulatory Commission, Terms and Conditions for Tariff Determination from Renewable Energy Sources Regulations, 2020 (2020), available at Link.}

^{3 Press Information Bureau, Government of India, Cabinet Approves the Scheme Titled Viability Gap Funding for Development of Battery Energy Storage Systems (BESS) (Sept. 6, 2023), available at Link.}

^{4 Paragraph 47, Cent. Elec. Reg. Comm’n, Petition No. 138/AT/2024, Order dated Jan. 2, 2025.}

^{5 Ministry of Finance, Department of Economic Affairs, Updated Harmonised Master List of Infrastructure Sub-Sectors (Oct. 11, 2022), available at Link.}

^{6 Ministry of Power, Amendment to the Operational Guidelines for the BESS VGF Scheme (Aug. 4, 2025), cl. 3.9, available at Link.}

^{7 The Power System Development Fund, or PSDF, is a sectoral fund used to support projects that strengthen the Indian power system and improve grid reliability. The later BESS VGF scheme proposes to use this fund to provide financial support for large-scale battery storage capacity.}

^{8 Press Information Bureau, Ministry of Power, Cabinet Approval / Scheme Details for the Original BESS VGF Scheme (Sept. 6, 2023), available at Link.}

^{9 SIGHT stands for ‘Strategic Interventions for Green Hydrogen Transition’. These incentives are government incentives under the National Green Hydrogen Mission, intended to support electrolyser manufacturing and green hydrogen production until the sector becomes commercially viable}

^{10  Cabinet Committee on Economic Affairs, National Green Hydrogen Mission (Jan. 4, 2023), available at Link.}

^{11 Ministry of New and Renewable Energy, Government of India, Scheme to Support Pilot Projects on New and Innovative Production Techniques and Applications of Green Hydrogen (Aug. 5, 2025), available at Link.}

^{12 Ministry of Power, Guidelines for Tariff Based Competitive Bidding Process for Procurement of Firm and Dispatchable Power from Grid Connected Renewable Energy Power Projects with Energy Storage Systems (February 2, 2024), available at Link.}

^{13 Ministry of New and Renewable Energy, Government of India, Non-requirement of NOC from FDRE PPA/PSA Procurer for ESS Charged Using Power Other Than RE Power (April 11, 2026), available at Link.}

^{14 Ministry of Power, Guidelines for Tariff Based Competitive Bidding Process for Procurement of Firm and Dispatchable Power from Grid Connected Renewable Energy Power Projects with Energy Storage Systems (June 9, 2023), available at Link.}

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