GreenCycles

India has set an ambitious goal of achieving 500 gigawatts (GW) of non-fossil-fuel capacity by 2030, with solar expected to contribute a significant share of that production. However, the rapid expansion of variable renewable energy sources, such as solar, presents increasingly pressing challenges to grid stability and reliability, as well as to demand management.

Solar-plus-storage systems—especially those designed to deliver dispatchable power during peak demand hours—can enable a smooth, clean energy transition in India. With their capacity to firm (stabilize) solar output and effectively match temporal alignment with demand, battery energy storage systems (BESS), in particular, facilitate employing solar energy to ensure grid reliability. Australia, Chile, the United Arab Emirates (UAE), the United States, and many European countries already leverage solar-plus-storage systems to enhance grid reliability. India could follow their example.

Historically, India has used transparent, competitive, well-designed tenders to successfully scale up renewable energy (RE) production. Extending this model to solar-plus-storage projects is both logical and necessary, but this must be done with caution. Solar-plus-storage projects are often complex, and tenders must be thoughtfully designed to manage risk allocation. This report examines India’s 500 GW target and the role energy storage must play in achieving it, including identifying some challenges India is likely to face. Ultimately, this report offers actionable solutions to the challenges identified, culminating in a playbook for designing robust solar-plus-storage tenders.

The introduction outlines India’s 2030 target of 500 GW non-fossil-fuel capacity and explains why energy storage is central to achieving this goal. The section attributes sluggish energy storage deployment to five key factors: requirement, technology, duration, location, and economics. The section highlights the benefits and growing popularity of solar-plus-storage projects using global examples.

Chapter 1 reviews the policy and tendering landscapes for energy storage in India, currently offered by India’s four renewable energy implementing agencies (REIAs): the Solar Energy Corporation of India (SECI), NTPC (formerly known as the National Thermal Power Corporation), NHPC (formerly known as the National Hydroelectric Power Corporation), and SJVN (formerly known as Satluj Jal Vidyut Nigam). The section also outlines the current tender types: round the clock (RTC), firm and dispatchable renewable energy (FDRE), and assured peak power supply. It then assesses the challenges of current procurement methods in encouraging the deployment of energy storage—namely, cost-optimal planning, offtaker risk, complexity in tender design, as well as the absence of other revenue streams for energy storage systems.

Chapter 2 presents the results of techno-economic modeling that compares various solar and storage configurations to identify the least-cost—or cost-optimal—pathways for providing reliable RE during peak hours. According to the Central Electricity Authority of India, the country will require energy storage capacity of 73.93 GW/411.4 gigawatt hours (GWh) by 2031–2032 (composed of 26.69 GW/175.18 GWh in pumped hydro storage and 47.24 GW/236.22 GWh battery energy storage systems) to sufficiently integrate the anticipated massive influx of renewables. The cost-optimal study’s findings, which are in line with those of the Central Electricity Authority, show that to support the planned rapid RE expansion and to maintain grid reliability, India will need 61 GW/218 GWh of storage capacity by 2030, and 96 GW/362 GWh by 2032. The majority of this capacity will be provided by BESS. India will need 51 GW batteries (20 GW of two-hour storage and 31 GW of four-hour storage) by 2030, as well as 87 GW batteries (20 GW of two-hour and 67 GW of four-hour) by 2032. Despite this projected need, at the end of December 2024, India’s total installed energy storage capacity was only 4.85 GW (4.75 GW pump hydro and 0.11 GW BESS). Approximately 360 GW of the needed RE capacity (85 percent) and 54 GW of storage capacity (90 percent) will be built in just nine states by 2030. A solar-plus-storage system with 2–4 hours of battery storage is cost competitive and also exerts a downward pressure on the average power procurement cost (APPC).

Chapter 3 offers a comprehensive guide to structuring solar-plus-storage tenders. It is organized around seven design components: technology pairing; storage sizing and duration norms; coupling configuration; siting and approvals; financial risks and incentives; business models; and storage and system operations.

Chapter 4 explores how California—especially through agencies such as the California Independent System Operator (CAISO) and the California Public Utilities Commission (CPUC)—has successfully integrated large-scale solar energy production and storage. It outlines policy targets and mechanisms (renewable portfolio standards, integrated resource planning, and resource adequacy programs), procurement practices (multi-resource tenders), and contracting models (long-term resource adequacy agreements and tolling contracts), including a review of the evolution of resource adequacy programs. The case study of California offers a potential pathway for the evolution of the Indian power market, centered on reliability targets (resource adequacy), linked resource procurement, a multi-resource tender design, an auction calendar to support better pipeline planning and prevent tariff undercutting, and the unlocking of the multiple value streams offered by battery storage.

India’s transition to a predominantly renewable power system will not succeed without firm, flexible capacity to back variable energy sources. Solar-plus-storage offers the most scalable, cost-effective, and cleanest solution. By aligning with international best practices and customizing tender designs to local realities, India can unlock a new wave of investment in solar-plus-storage, delivering both climate ambition and grid resilience.

Solar-Plus-Storage Tendering

Key Recommendations

Project Configuration, Technology Selection, and Performance

The technical requirements for a project must be clearly defined to reduce project risks and promote uniformity across tenders. This includes but is not limited to specifying technology pairings (i.e., Solar-Plus-Energy Storage Systems), limiting the charging source, and defining peak availability criteria.

▲ Table 1: Recommended Approaches to Project Configuration, Technology Selection, and Performance

Project Location and Approval Processes

Transparent site selection and streamlined approval processes reduce implementation delays. Linking projects to high-resource zones and existing grid infrastructure enhances reliability and lowers integration costs.

▲ Table 2: Recommended Approaches to Project Location and Approval Processes

Payment Security Mechanism: A Three-Tiered Model

Developers and financiers require reliable assurance of payment, mitigating risk and concerns of non-payment. A tiered mechanism ensures liquidity, reduces counterparty risk, and balances responsibility between buyers and governments.

▲ Table 3: Tiered Payment Security Mechanism

Performance Bank Guarantees (PBGs)

There should be greater flexibility in PBG instruments to allow broader participation by reducing financial constraints, while still ensuring project delivery security.

▲ Table 4: Recommended Approach to Performance Bank Guarantees

Power Offtake Arrangements

Robust power offtake arrangements should be incorporated in tender design, and doing so will ensure project viability and system efficiency. Moreover, compensation and penalty mechanisms align incentives and protect both buyers and developers.

▲ Table 5: Recommended Approaches to Power Offtake Arrangements

Introduction

At the 26th United Nations Climate Change Conference of the Parties (COP 26), held in Glasgow in November 2021, Prime Minister Narendra Modi announced India’s pledge to install 500 GW of non-fossil capacity by 2030, accounting for 50 percent of its estimated energy mix. Of the 500 GW, 450 GW would be sourced from renewable energy (RE), namely solar and wind. Since then, India has made massive strides toward these ambitious goals. As of June 2025, India had installed approximately 185 GW of RE (excluding large hydro) capacity, accounting for 38 percent of current total installed generation capacity. Yet RE’s share in total power generation is only 14 percent of the country’s total production. By 2030, India aims to add another 250 GW of RE. However, unless the new RE capacity is firmed up to reduce intermittency, the influx of large-scale renewables will create operational challenges for India’s distribution utilities. These potential challenges relate to what is referred to as the duck-curve phenomenon, where there is a timing imbalance between peak production (particularly for solar) and peak demand. This relationship is often almost inversely proportional to system load, especially for solar power, which comprises the majority of India’s newly installed RE. The planned high levels of installed solar capacity will create an increasing imbalance between electricity supply and demand, resulting in a drop in net demand during midday hours, when solar generation is high, followed by a sharp increase in demand as the sun sets (evening peak hours) and solar generation decreases.

Meeting India’s 2030 target while maintaining grid stability requires massive investments into energy storage systems (ESSs) to stabilize the intermittency and variability of RE sources. Energy storage is crucial to firming RE generation while increasing its share in the grid. ESSs can help mitigate the duck curve by storing excess solar energy generated during the day and then discharging it during evening peak-demand periods. Moreover, ESSs can serve additional functions such as helping maintain frequency and voltage stability of the grid, ensuring grid balance, and assisting in the prevention of power outages by flexibly discharging when needed and storing excess energy when possible. Energy storage also supports bulk energy services like energy arbitrage and energy management, including improving power quality and enabling load-leveling.

India’s power demand is rapidly increasing and, without energy storage, will result in significant evening-peak shortages. In its 2023 National Electricity Plan, the Central Electricity Authority of India (CEA) estimated that India will need 73.93 GW/411.4 GWh of energy storage by 2031–2032 to sufficiently integrate the planned massive influx of renewables. The current plan anticipates 26.69 GW/175.18 GWh of storage from pumped storage projects (PSPs) and 47.24 GW/236.22 GWh from battery-energy storage systems (BESS). India has a long way to go to meet its goals. By December 2024, the total installed ESS capacity in India was only 4.85 GW (4.75 GW PSP and 0.11 GW BESS).

Five key issues are primarily responsible for the protracted deployment of energy storage in India: requirement, technology, duration, location, and economics. Policymakers and utilities need to answer the following questions to understand and deliver on the need for more energy storage:

1. What is the storage requirement (i.e., the capacity required)?

2. What technologies should be prioritized (PSP, BESS, others)?

3. What should the duration of storage be (2 hours, 4 hours, 6 hours, 8 hours, etc.)?

4. Where should the storage facilities be located?

5. How much will it cost (i.e., the potential impact of capital investment on power tariffs)?

Once these five questions are addressed, the deployment of energy storage becomes a function of utilities’ procurement strategies—that is, how well the tenders and contracts are structured.

According to BloombergNEF, the global energy storage market (excluding PSP) is expected to grow by 35 percent (to 94 GW or 247 GWh) in 2025, with subsequent compound annual growth around 14.7 percent, reaching an additional 220 GW (or 972 GWh) of growth in 2035. Though PSP projects are not suitable for co-location due to siting constraints, environmental restrictions, and the time required for construction, the same cannot be said for BESS projects. Battery energy storage systems can be purchased independently or can be paired with RE sources via hybrid tenders. In addition, BESS capacity can be located independent from or co-located with RE sources. Co-location through hybrid tenders offers cost advantages, and can lead to faster deployment of energy storage. Overall, a co-located solar-plus-storage project is economical, provides reliable grid support for better integration of renewables, and can lead to faster deployment of energy storage to avoid power shortages.

Co-located solar-plus-storage projects are increasingly popular among India’s global allies. In the United States, for example, 98 percent of new solar capacity proposed by the California Independent System Operator (CAISO)—which covers 80 percent of California and part of Nevada—is paired with BESS. In the non-ISO portion of the western United States—covering parts of 15 states—87 percent of all proposed solar projects are co-located with BESS. Under Australia’s Capacity Investment Scheme, 40 percent of approved projects in the first tender (2024) were co-located solar-plus-storage proposals. The world’s two largest projects—the UAE’s Masdar project (5.2 GW solar plus 19 GWh BESS) and Chile’s Oasis de Atacama project (2 GW solar plus 11 GWh BESS)—are both co-located solar-plus-storage. In addition, Bulgaria, Greece, Israel, Panama, and Spain have either already issued or are in the process of issuing hybrid tenders. Finally, in fiscal year (FY) 2024–25, India issued five hybrid tenders—two by the Solar Energy Corporation of India (SECI) and one each by NHPC, NTPC RE, and SJVN—and discovered competitive tariffs. However, there were not many takers for these tendered projects due to several factors, including the absence of an assured buyer, high trading margin costs, and hedging by utilities due to falling tariffs.

Tenders and tender documents are the primary legal and regulatory instruments for power procurement and project structuring. They define critical aspects such as bankability, tariff competitiveness, technical configurations, and risk allocation, all of which directly influence investment decisions and project viability. A well-designed tender can drive cost reductions through competitive bidding while also ensuring that projects are completed on time. Ensuring that tenders have clear technical specifications, robust payment security frameworks, and effective risk mitigation measures is essential to attract private investment at scale.

Poorly structured tenders—specifically, those with no pre-identified buyer, vague technical guidelines, unclear cost planning and payment guarantees, or poor support for risk mitigation—have led to asymmetric renewable energy and storage deployments, opaque and expensive tariffs, and hesitancy from developers, which, in turn, results in high tender undersubscription. This has been observed in both Indian and global contexts, where tenders that lacked clarity on storage sizing, grid interaction, or payment security have undermined investor confidence. Conversely, well-designed tenders have enabled rapid deployment and unlocked cost efficiencies through competitive bidding.

Worldwide, governments have recognized the power of tendering not only as a contracting mechanism, but also as a market-shaping tool. In California, for example, procurement mandates and standard offer contracts have made co-located solar and storage the dominant model. California’s tenders incorporate clear valuation of capacity services, siting and integration timelines, and locational value, which, in combination, have unlocked private capital at scale. To help deliver the Australian government’s renewable electricity target of 82 percent by 2030, the Capacity Investment Scheme has awarded approximately 10 GW and 12 GWh of RE and storage projects in less than two years, through two large-scale tender rounds and two smaller pilot tenders. The Australian tenders were designed to emphasize the system security benefits, ancillary services, and cost-savings potential of co-located projects. Meanwhile, to encourage co-located projects, Germany’s Innovation Tenders program requires hybrid projects and have been consistently oversubscribed through thoughtful tariff subsidies. Most of the contracts from the German tender were for solar-plus-storage projects, although the tenders are technology agnostic.

Deliberately designed tenders can accelerate storage deployment and investment. Adapting and scaling these successful procurement models to fit India’s growing energy landscape is crucial to enable the successful deployment of 500 GW of RE without creating operational challenges for the grid, something which the Indian CEA recognized in its February 2025 policy advisory.

Current Policy and Tendering Landscape for Energy Storage in India

Policy Landscape

India has implemented several initiatives aimed at enhancing the role of energy storage and thus accelerating the deployment and integration of RE (see Figure 1 below). In 2017, the Indian Central Electricity Regulatory Commission (CERC) released a staff paper on the introduction of electricity energy storage that highlighted the grid applications, ownership structures, operational frameworks, and challenges of such endeavors.

In May 2018, the government launched the Wind-Solar Hybrid Policy, which, for the first time, allowed the deployment of energy storage technologies to enhance grid stability by balancing the demand-supply gap. In 2022, the Ministry of Power (MoP) introduced Guidelines for the Procurement and Utilization of BESS across Generation, Transmission, and Distribution Assets, while also incorporating the use of BESS for ancillary services to reinforce grid resilience. Also in 2022, the MoP introduced the Energy Storage Obligation (ESO), mandating an initial storage capacity of 1 percent in FY 2023–24, scaling up to 4 percent by 2029–2030 to meet growing energy needs.

In 2023, the MoP took steps to further advance India’s energy storage agenda by issuing comprehensive guidelines for the development of pumped storage projects. It released a national framework for promoting ESSs with the objective of enabling round-the-clock power supply from RE plants, ensuring grid stability and reliability. Additionally, the government introduced a Viability Gap Funding (VGF) mechanism to accelerate the deployment of large-scale BESS, with a target of setting up 4,000 MWh of capacity by 2025–2026. Under this scheme, up to 40 percent of the capital cost can be covered through government funds, incentivizing investments and addressing financial barriers in the energy storage sector. These policies resulted in a large number of energy storage tenders in 2024.

In February 2025, the MoP issued an advisory that all new RE plants must include a co-located energy storage system with an equivalent to 10 percent of the installed solar capacity and a minimum of two-hour duration. In April 2025, the target of the VGF was expanded from 4,000 MWh to 13,200 MWh, reflecting the declining cost of battery storage. To further support the deployment of BESS, a new VGF scheme for 30 GWh, with a financial outlay of INR 5,400 crore (USD 630 million), was introduced to address storage needs projected for 2028. Additionally, the government extended the waiver of Inter-State Transmission System (ISTS) charges until 2028, providing further policy support for BESS adoption.

▲ Figure 1: Policy Landscape of RE and Energy Storage in India. Source: Authors’ analysis.

Tendering Landscape

To promote the bidding trajectory of RE and to achieve 500 GW capacity from non-fossil fuels by 2030, the Indian government plans to install 50 GW of RE capacity annually. To that end, the government has recognized four renewable energy implementing agencies (REIAs): SECI, NTPC, NHPC, and SJVN. These organizations release tenders covering both RE and ESS as requests for proposals. The bidding process for the tenders is an e-reverse auction, primarily through single stage, two-part bids, with both a technical and financial bid. In addition, several Indian states have issued stand-alone ESS tenders incentivized by the central government’s VGF.

REIA tenders can be broadly classified into five types: round the clock (RTC) tenders, which combine RE with thermal storage or ESS; firm and dispatchable renewable energy (FDRE) tenders that have a mandatory ESS component; assured peak power supply tenders; stand-alone storage tenders; and solar-plus-storage tenders.

1. Round-the-clock (RTC) tenders: In most RTC tenders, ESS is the only optional component, with an annual capacity utilization factor (CUF, a measure of actual production compared to total potential) of at least 85 percent. For non-RE power, a tariff escalation is permitted for fuel and transportation only. If there is a shortfall in generation below the specified CUF, a penalty of 300–400 percent power tariff is imposed.

   A notable example of an RTC tender is SECI’s RTC I, which was oversubscribed and later awarded to ReNew Power at an initial tariff of INR 2.90 per kWh, with an annual escalation rate of 3 percent until the 15th year. In SECI RTC I, renewable energy power can be augmented with ESS, should the developer require it. Another RTC is the 2,500 MW SECI RTC II, which had a weighted average tariff structure of fixed (RE and non-RE) and variable (RE and non-RE) energy sources; this tender was later canceled due to high price discovery, undersubscription, and withdrawal of buyer. In May 2025, SECI completed the auction for 420 MW (out of a total 1,200 MW tendered capacity) under RTC-IV, which mandated the inclusion of energy storage. The lowest quoted tariff was INR 5.06 per kWh, and ESS was required to deliver power during specified four-hour peak periods in both the morning and evening.

2. Firm and dispatchable RE (FDRE) tenders: FDRE tenders have a mandatory ESS component, and they follow a single tariff that includes both RE and ESS, with the ESS being charged via RE. Among the 13 different FDRE tenders currently available, there are two distinct variants: load-following and assured peak supply. Load-following FDRE tenders have a demand fulfilment ratio (DFR) of 75–90 percent. One load-following FDRE tender—SECI FDRE 4—initially tendered at 1,260 MW (later amended to 630 MW) and successfully concluded at a tariff of INR 4.98 per kWh. Assured peak supply FDRE tenders specify a minimum CUF of 40 percent with four hours at peak times and at least 90 percent demand fulfillment during the peak hours. Examples include the 3,000 MW NTPC FDRE 1 (2023), the 1,200 MW NTPC FDRE 2 (2024), the 1,500 MW NHPC FDRE 1 (2023), the 1,200 MW NHPC FDRE 2 (2023), the 1,500 MW SJVN FDRE 1 (2023), and the 1,200 MW SJVN FDRE 2 (2024).

3. Assured peak power supply tenders: Based on either RTC or FDRE tender guidelines, assured peak power supply tenders include a mandatory co-located ESS component. Two examples of RTC-guideline-based tenders are SECI’s Peak Power Supply 1 and 2, each for 1,200 MW, issued in 2019 and 2022, respectively. Both tenders were successfully subscribed. The tenders specify that for every “X” MWs of RE, “X” MWh of ESS should be installed with RE generators. For the SECI Peak Power Supply 1 (2019) tender, the tariff structure was a peak and off-peak tariff, with off-peak defined at INR 2.7 per kWh. The peak hour supply for this tariff was six hours. The SECI Peak Power Supply 2 (2022) tender had a single tariff with a 2–4 hour peak hour requirement. In the 2022 tender, during the peak hours, twice the rated power was to be provided as energy to the offtaker (i.e., for each 100 MW of project capacity, the developer should supply up to 200 MWh of energy during peak hours). The offtaker substations are already identified in this tender. In contrast, an assured peak power supply tender based on FDRE guidelines is the 8,000 MWh SECI FDRE 6. Its requirements included that the ESS should be co-located and should have a capacity of four peak hours (non-solar hours). The buying entity can offtake 4 MWh of energy for every 1 MW rated capacity during the peak hours, and any shortfall can result in a penalty of 1.5 times the power-purchase costs. The tender is closed at a tariff of INR 8.5 per kWh, but the capacity was capped at 656 MW due to the insufficient number of bidders.

4. Stand-alone ESS tenders: As the name implies, these tenders are issued exclusively for ESSs with no accompanying RE component. The storage systems are typically required to provide power for a specified discharge duration. These tenders may either be technology agnostic or may explicitly call for battery-based storage solutions. The tariff structure is generally specified in INR/MW/month.

   Notable examples of stand-alone ESS tenders include the 500 MW/3,000 MWh NTPC tender floated in 2022 and the 1,000 MW/2,000 MWh SECI tender issued in 2024. In 2022, tariffs were relatively high, ranging from INR 10.83 to 27.92 lakh/MW/month, largely due to early-stage market maturity and higher battery costs. However, 2024 saw a significant price drop, with tariffs ranging from INR 3.81 to 4.41 lakh/MW/month, reflecting falling battery prices and improved market confidence. A further decline in prices was observed in 2025, following the announcement of additional VGF. For instance, NHPC’s 500 MW/1,000 MWh stand-alone battery storage tender witnessed record-low tariffs of INR 2.08 lakh/MW/month. In these projects, the buying entities are responsible for procuring charging power.

5. Solar-plus-storage tenders: These tenders are distinct in that they specify the RE technology—solar—and mandate co-location with ESS. This configuration offers clear advantages, such as the smoothing of renewable output, optimized use of evacuation and site infrastructure, and reduced grid congestion.

Bidders are required to quote a single tariff (INR/kWh) and declare the annual CUF for the project. They must also guarantee assured peak power supply during specified peak hours. During off-peak periods, the ESS can be used for other applications, with up to 5 percent of stored energy allowed to be sold on the market.

Prominent examples include SECI’s 1,200 MW Solar with 600 MW/1,200 MWh ESS tender, which mandated a minimum CUF of 17 percent, and was awarded at a tariff of INR 3.41 per kWh, and SECI’s 2,000 MW Solar with 1,000 MW/4,000 MWh ESS tender, awarded at a tariff of INR 3.52 per kWh.

Building on this momentum, SECI has floated additional tenders, including the 2,000 MW solar with 1,000 MW/4,000 MWh ESS and the 1,200 MW solar with 600 MW/3,600 MWh ESS, the latter being the first of its kind to require six-hour storage.

In parallel, NHPC and SJVN have also released 1,200 MW solar tenders with four-hour ESS, following similar design principles.

Figure 2 presents various tenders with their respective renewable energy and storage capacities, as well as the winning tariff. The tariff trends show that the prices are declining for the different types of RE and ESS tenders.

▲ Figure 2: Tender Capacities and Winning Tariffs. Source: Authors’ analysis from assorted REIA-tendering documents.

As of July 2025, there are 37 different tenders from different central REIAs. The tender status, tender types, and allocation of tenders by different organizations are shown in Figures 3a, 3b, and 3c, respectively.

▲ Figures 3a, 3b, and 3c: Tender Status, Tender Types, and Tenders by REIA. Source: Authors’ analysis.

In addition to the central government tenders, states such as Maharashtra, Gujarat, Karnataka, Telangana, and Rajasthan have issued their own ESS-linked or stand-alone storage tenders. For instance, the Maharashtra State Electricity Distribution Company Limited (MSEDCL) issued a tender combining 1,600 MW thermal and 5,000 MW solar that saw a weighted average tariff of INR 4.08 per kWh. The Gujarat utility—Gujarat Urja Vikas Nigam Limited (GUVNL)—was the first in the country to issue a low tariff of INR 4.49 lakhs/MW/month in March 2024 for its stand-alone storage tender. GUVNL’s next tender brought the tariff down further, to INR 3.72 lakhs/MW/month. Supported by 30 percent VGF from the central government, utilities in Rajasthan, Maharashtra, Gujarat, Telangana, and Karnataka witnessed steep declines in tariffs for stand-alone storage. VGF-supported auctions by MSEDCL (Maharashtra) and RVUNL (Rajasthan) saw initial tariffs of INR 2.19–2.21 lakhs/MW/month for two-hour storage projects.

Challenges in the Existing Tendering Landscape

As India aims to add another 250 GW of renewable energy to its existing 185 GW of RE capacity, the influx of large-scale renewables will create an electricity demand-supply imbalance—specifically, a drop in net demand during midday hours, when solar generation is high, and a sharp increase in demand as the sun sets (evening peak hours)—leading to operational challenges, unless paired with energy storage.

Despite the policy push from the central government and a portfolio of released tenders, the actual deployment of ESS is slower than what is required to avoid power shortages. Figure 4 illustrates the massive difference between targeted and achieved ESS deployment.

▲ Figure 4: ESS Target vis-à-vis Actual Installation. Source: Central Electricity Authority, “Advisory on Co-Locating Energy Storage Systems with Solar Power Projects to Enhance Grid Stability and Cost Efficiency,” February 18, 2025.

Several factors have limited the successful deployment of energy sources.

1. Absence of coordination between the central and state governments

   Of all tenders issued between April 2023 and June 2025, REIAs have canceled tenders totaling 11.4 GW. During the same period, projects with a cumulative capacity of 43.9 GW have been awarded but do not have assured offtakers. This is indicative of the absence of coordination between the central and state governments, which manifests in two ways:

   I. Lack of cost-optimal planning

   For India to meet its 500 GW target, it needs to install 50 GW of RE capacity annually from 2025 until 2030. This rate dictates the tenders issued by REIAs, not scientific planning and analysis. As a result, even though there is competitive price discovery, it is not certain that the capacity auctioned, and the prices offered, are the cost-optimal pathways for different offtakers. The pressure to issue 50 GW of tenders annually has created a cycle of back-to-back auctions, with each round pushing tariffs lower. This has led various distribution companies (DISCOMs) to adopt a “wait-and-watch” approach, delaying commitments in anticipation of even lower prices. In effect, the absence of coordinated, cost-optimal planning, driven by the mechanical pursuit of annual targets, is undermining the very objectives these tenders are meant to serve.

   II. High offtaker risk

   Securing a definite offtaker is crucial for project viability. However, many tenders suffer from misalignment between bid issuance and offtaker demand and infrastructure (non) readiness. Coupled with confusion surrounding the ISTS waiver and anticipation of further reduction in tariffs, this misalignment has dissuaded states and DISCOMs from signing power purchase agreements (PPAs), putting the financial viability of projects at risk and delaying the overall development process. Examples include SECI’s 2,000 MW Solar with 1,000 MW/4,000 MWh ESS, the 1,200 MW NHPC FDRE 2, the 1,200 MW SJVN FDRE 2, and the 1,200 MW NTPC FDRE 2, among others.

2. Complex FDRE tender design

   FDRE tenders, which mandate ESS, dominate the tenders issued by the REIAs, yet their high undersubscription rates mean less ESS on the ground. One of the most cited reasons for undersubscription is tender design complexity, particularly regarding stringent power delivery, availability conditions, and solution complexity, along with strict financial prerequisites and penalties. FDRE tenders previously required a 90 percent demand-fulfillment ratio across all time blocks within a contract month, which was later relaxed to 75 percent; failing to achieve this incurred a penalty of 1.5 times the PPA’s tariff. This forced project developers to oversize the generation capacity to mitigate shortfalls. The oversizing was done by increasing wind capacity and reducing the ESS capacity, further contributing to the protracted deployment of energy storage. The examples of the Maharashtra State Electricity Distribution Company Limited (MSEDCL) and SJVN’s FDRE PPA support the need for oversizing. The two groups signed a PPA to supply 1.47 GW of FDRE power in 2024. The state regulator’s order suggests that, to meet its power supply obligation of 1.47 GW, developers would have to build 3.6 GW of RE (1.4 GW solar and 2.2 GW wind), but merely 461 MWh of ESS.

3. Limited revenue sources for ESSs

   Most tenders provide compensation only for availability during specific hours, ignoring the full range of value these systems can provide—such as frequency regulation, peak shaving, voltage support, or spinning reserves. The absence of multipart tariff mechanisms or an enabling ancillary services market limits revenue-stacking opportunities, reducing project bankability, deterring private investment in the technology, and further protracting ESS deployment.

4. Trading-margin economics

   REIAs specify a fixed trading margin payable by utilities or DISCOMs on every unit of electricity procured from developers. While this enables standardization and administrative ease, it can become a point of concern in large-capacity tenders. Given that the trading margin is nonnegotiable, utilities and DISCOMs may perceive it as an added financial burden, especially when the scale of procurement leads to significant cumulative costs. This lack of flexibility may also limit cost optimization opportunities in increasingly mature and competitive power markets.

5. Operational challenges with multistate RE tenders

   In multistate renewable energy and storage tenders, operational harmonization is often hindered by regional disparities in demand patterns and solar availability. Two key challenges are the following:

   I. Divergent peak demand definitions

   States often define peak demand periods differently—ranging from early morning agricultural loads to late evening residential peaks—complicating uniform tender design, evaluation criteria, and dispatch planning across regions.

   II. Geographic variation in solar windows

   Differences in sunrise and sunset times across states affect solar generation profiles and the charging and discharging schedules of storage.

6. Land access and transmission hurdles

   Land availability remains a critical challenge, as solar-plus-storage projects require large pieces of barren or nonagricultural land with high solar potential. Such locations are often remote and, relatedly, lack adequate transmission connectivity, creating a second major bottleneck. In many cases, the development of transmission evacuation infrastructure takes longer than the construction of the solar and storage facilities themselves. Current tender frameworks place the full financial burden of this on developers, with limited coordination or assurance from transmission utilities, negatively affecting project bankability and timelines.

7. Market hesitation by utility companies

   In 2025, many utilities remain hesitant to sign storage contracts, anticipating further price declines in storage technologies. This reluctance has stalled procurement activity, prompting the announcement of a new VGF scheme for 30 GWh of storage. Under this scheme, tendering is expected to be completed within nine months to accelerate deployment and build market confidence.

8. Confusion around ISTS waiver

   A full ISTS waiver is available for both BESS and pumped hydro projects until June 2028. For co-located BESS, the project must be commissioned (fully operational) by June 30, 2028, while for pumped hydro, construction work must begin by that date. For stand-alone BESS, a conditional waiver is provided with no clear time horizon. Moreover, the waiver contains several ambiguities that affect the tendering landscape. Unanswered are questions about whether co-location requires physical proximity, shared interconnection, or just being tied to the same ISTS substation. Additionally, the “out-of-state consumption” clause lacks clarity on applicability in hybrid or partially intra-state use cases. For non-co-located ESS, the waiver is granted to drawee entities, but not to developers, creating further uncertainty in contractual and financial responsibilities. Finally, while ISTS charges are waived, transmission losses are not, and there is no guidance on how this affects project economics.

The Cost-Optimal Pathway to 500 GW

National Picture

CLEAN POWER: THE MOST COST-OPTIMAL PATHWAY FOR INDIA

The most cost-optimal pathway forward for the power sector centers on meeting India’s target of 500 GW of non-fossil fuel capability by 2030. Given the deep reduction in solar-plus-storage costs in recent years, new coal investments (apart from what is already under construction, around 25 GW) are not cost effective. Approximately 360 GW of the RE capacity (85 percent) and 54 GW of the storage capacity (90 percent) will be located in just nine states in 2030. While solar energy will be generally well spread out, most of the wind capacity will be located in just six states, as they have the highest wind potential. For example, offshore wind projects are often only built off the coasts of Tamil Nadu and Gujarat. Storage largely coincides with solar states and load centers.

▲ Table 6: 2030 Maximum RE and Storage Capacity by State. Source: Authors’ analysis.

ENERGY STORAGE NEEDED: 61 GW BY 2030, 96 GW BY 2032

To support the rapid RE expansion in India and maintain grid reliability, India will need 61 GW/218 GWh of storage capacity by 2030, and 96 GW/362 GWh by 2032. The majority of this will be battery based:

1. By 2030—51 GW batteries (20 GW of two-hour, 31 GW of four-hour); 9 GW pumped hydro

2. By 2032—87 GW batteries (20 GW of two-hour, 67 GW of four-hour); 10 GW pumped hydro

These systems are critical for balancing evening and morning demand peaks, shifting low-cost solar energy into high-value hours, and reducing reliance on inflexible coal.

If battery costs rise or pumped hydro becomes cheaper, pumped hydro could account for 17–22 GW of storage by 2032, though siting constraints would limit flexibility.

▲ Figure 5a: ESS Additions by State by 2030 / Figure 5b: Map of ESS Additions by State by 2030. Source: Derived from authors’ modeling using PLEXOS energy modeling software.

ENERGY STORAGE DEPLOYMENT LOCATIONS

Energy storage deployment must align with the locations of solar capacity, load centers, and states lacking hydro or other peaking resources. Table 7 contains required storage by state for the states in which most new RE will be sited.

▲ Table 7: Required Energy Storage by State. Source: Nikit Abhyankar, Shruti Deorah, and Amol Phadke, “Least-Cost Pathway for India’s Power System Investments through 2030,” Lawrence Berkeley National Laboratory.

Some storage will also be needed in the northeast of the country to integrate local solar production and reduce new transmission needs. Co-locating batteries with solar offers 15–20 percent cost savings by sharing inverters, grid access, and balance of systems (BOS) components, advantages unavailable with pumped hydro.

DETERMINING INDIA’S STORAGE-DURATION NEEDS

India’s immediate storage needs are dominated by two-hour batteries, which enable utilities to address evening peaks. By 2027, 21 GW of storage will be required to avoid peak shortages, with batteries accounting for 19 GW.

Beyond 2027, four-hour batteries will become essential, supporting deeper daily shifts and seasonal balancing. Most batteries will cycle once daily—charging from mid-day solar and discharging during evening peaks, delivering 300–350 cycles per year.

IMPACT ON POWER PROCUREMENT COSTS

Solar-plus-storage exerts downward pressure on the average power procurement cost (APPC). As battery storage shifts excess RE from low-demand to high-demand hours, the following will occur:

1. The system will require less expensive peak generation from inefficient thermal units.

2. RE curtailment will drop, especially during monsoon and spring seasons.

3. Storage will enable greater utilization of low-cost solar (INR 2.5 per kWh) during expensive evening hours (INR 5–6 per kWh).

Planning models show that, despite the addition of storage, APPC in almost all major states is expected to decline by 5–10 percent by 2032 compared with 2024 levels due to declining RE and battery costs, the displacement of expensive coal (peaking and baseload), and greater capacity utilization of existing assets. (Detailed modeling results are provided in appendix Figure A1-1).

Subnational Pathways

Least-cost modeling for FY 2031–32 in the Indian states of Maharashtra, Madhya Pradesh, Andhra Pradesh, Karnataka, and Tamil Nadu reinforce the national trends.

▲ Table 8: FY 2031–32 Least-Cost Modeling by State. Source: Derived from author’s modeling using GridPath energy modeling software.

Across states, solar-plus-storage consistently reduces procurement costs, enhances flexibility, and displaces fossil capacity. (Detailed results and state-level expansion figures are provided in appendix Figures A2-1–A2-5.)

Designing a Hybrid Tender

The cost-optimal pathway results provide answers primarily related to five key parameters: requirement, technology, duration, location, and economics—specifically, (1) the storage requirement (capacity required); (2) the choice of technology (PSP, BESS, or others); (3) the duration of storage (two hours, four hours, six hours, or eight hours); (4) where the tender should be located; and (5) how much it will cost (e.g., the cost of adding storage on power tariffs).

Once these five parameters are settled, the deployment of energy storage becomes a function of utility procurement strategy, which is fundamentally dependent on the structure and design of tenders and contracts. Drawing upon the findings of the cost-optimal pathways study, this section discusses three essential parameters that will facilitate design of a robust hybrid tender in India. To discuss the three parameters, the section puts forth key questions that need to be answered while designing tenders.

Project Configuration (Parameter 1)

TECHNOLOGY PAIRING, STORAGE SIZING, AND DURATION

Solar is a predictable resource, making it easier to store and discharge generated energy during peak hours. Physically, it is easier to co-locate solar and battery storage compared to wind power and battery storage, as the latter requires larger space availability and grid infrastructure. Co-locating batteries with solar offers 15–20 percent cost savings from shared inverters, grid access, and balance of system (BOS) components, advantages unavailable with pumped hydro. In terms of technology pairing, solar-plus-battery storage is the most cost-effective and simple option.

▲ Table 9: Key Parameters in Designing Hybrid Tenders

The cost-optimal pathway study revealed that India’s immediate storage needs are dominated by two-hour batteries, which are essential to address evening peaks. Four-hour batteries will become essential after 2027 to support deeper daily shifts and seasonal balancing. Most batteries will cycle once daily—charging midday and discharging during evening peaks—delivering approximately 300–350 cycles per year.

Specifying minimum BESS capacity is a fairly common practice in India and globally, with a typical configuration between 50–100 percent of total solar capacity. The five solar-plus-storage co-located tenders issued in FY 2025 by SECI, NTPC, NHPC, and SJVN specified a BESS-to-solar sizing ratio of 50 percent.

Solar and battery storage is also the dominant technology pairing worldwide, and specifying the BESS-to-solar sizing ratio in tenders and requests for proposals is considered to be best practice. In the United States, solar-plus-storage projects constituted 61 percent of total operating hybrid generation assets in late 2023. Solar-plus-storage projects dominate the California market, with 87 percent of all solar projects paired with energy storage. Solar-plus-storage accounts for nearly a third (500 GW out of a total of 1,450 GW of RE) of the solar (1,100) and wind (350) projects in the U.S. interconnection queue. In terms of sizing, a typical project configuration in the United States is same as that in India. In Australia’s CIS tenders, the majority of awarded capacity is solar-plus-storage with a BESS-to-solar sizing ratio of 100 percent of PV capacity. The world’s two largest renewable energy-plus-storage projects—in Chile (2 GW solar plus 11 GWh storage) and the UAE (5.2 GW solar plus 19 GWh battery storage)—are solar-plus-storage. Spain’s hybrid auctions under its PERTE ERHA initiative heavily favored solar and storage projects, awarding 880 MW plus 1809 MWh ESS, while the Dubai Electricity & Water Authority’s (DEWA) Solar Park phase VII (1,600 MW solar plus 1,000 MW BESS) has a specified storage capacity of 62.5 percent of associated solar capacity.

Recommended Project Configuration (technology pairing, storage sizing, and duration)

Solar PV paired with battery storage is recommended, with a BESS-to-solar sizing ratio of 50–100 percent and storage duration of 2–4 hours.

COUPLING CONFIGURATION

A solar-plus-storage project can be coupled in two ways. AC-coupled systems involve separate inverters for the PV and battery components, while DC-coupled systems include a single shared inverter for both the PV and battery. A DC-coupled system can be configured into two subtypes: (1) loosely coupled systems that use a bidirectional inverter that allows for charging from either the coupled PV or the grid; and (2) tightly coupled systems that involve hardware (or controls) that disallow grid charging.

The choice between AC or DC coupling boils down to the purpose of the project. In the United States, developers prefer AC coupling, possibly due to the ease of retrofitting and various operational flexibilities favored by developers over cost efficiency. There are, however, DC-coupled projects in the United States, such as the Hickory Park Solar project in Georgia (200 MW PV and 40 MW/80 MWh BESS), the Lāwa’i Solar project in Hawai’i (28 MW PV and100 MWh BESS), and Arizona’s Gila River Power Station (20 MW PV and 10 MW/40 MWh BESS). Globally, there is not a preferred choice of coupling. In Australia, there are solar-plus-storage projects with both AC and DC coupling. In the Middle East, DEWA’s Solar Park phase IV project uses AC coupling for grid interaction. Chile’s Oasis de Atacama project, Latin America’s largest solar-plus-storage project (2 GW PV and 11 GWh BESS), employs DC-coupled architecture. In Europe, Spain has adopted DC coupling in utility-scale solar storage projects such as the Arañuelo III (40 MW PV and 9 MWh BESS), whereas AC coupling dominates in Germany.

▲ Table 10: AC Versus DC Coupling. Source: Grid Controller of India Limited, “Suggestions on the Staff Paper on modifications in the GNA Regulations,” December 12, 2024; and Natalie Opie, “AC vs DC-coupled BESS: the pros and cons,” RatedPower, April 24, 2023.

Recommended Coupling Configuration

From a purely economic standpoint, a DC-coupled system with bidirectional inverters is recommended to ensure high system efficiency and shared capital expenditure, decreasing overall project cost.

However, for greenfield solar-plus-storage projects in India, the choice of AC or DC coupling should be made by evaluating the relative economics of cost reductions offered by a DC-coupled system with the enhanced operational flexibility offered by an AC-coupled system. The utility does not need to specify the coupling configuration in the tender, but the implications of AC versus DC coupling should be addressed through the design of other parameters, such as penalty mechanisms for not meeting the minimum CUF availability or minimum peak availability.

A study should be conducted to assess the impact of different coupling techniques and the role of power electronic converters and inverters on overall system performance, focusing on technical, policy, and economic implications in enhancing energy conversion efficiency, grid stability, and system reliability.

PERFORMANCE PARAMETERS

Capacity utilization factor (CUF), round-trip efficiency (RTE), and peak availability are critical parameters that directly impact the technical viability, economic efficiency, and overall reliability of solar-plus-storage projects. CUF measures the actual energy delivered as a percentage of the installed capacity, influencing tariff competitiveness and project sizing. RTE, which represents the percentage of energy recovered after charging and discharging the battery, determines overall system efficiency and lifecycle economics, especially when storage duration requirements are high. Peak availability ensures that the hybrid system can reliably supply power during critical demand windows, such as evening and morning peaks, making it a key metric for resource adequacy and grid stability. Including well-defined criteria for these parameters in tender documents creates clear performance obligations, reduces ambiguity for developers, and ensures that projects deliver the intended flexibility and firm capacity benefits to the grid.

SECI has issued the most solar-plus-storage tenders (four), with their tenders prescribing the following CUF, RTE, and peak availability norms for energy supply during non-peak hours:

▲ Table 11: CUF norms. Source: Solar Energy Corporation of India Limited.

• RTE norms

There are no RTE norms identified in solar-plus-storage tenders, but the stand-alone battery storage tenders issued by SECI, other REIAs, and DISCOMs in India specify ≥ 85 percent for lithium-ion based systems.

• Peak Availability

There are no norms specified in the tenders, but as a best practice measure to ensure power availability during the peak hours (when the grid needs it most), tenders should mention the peak availability requirements. Stipulating ≥ 90 percent availability ensures that project developers follow sound project design strategy and are not oversizing solar PV relative to battery storage. This is also in line with guidelines issued by the Ministry of Power.

SECI’s two solar-plus-storage tenders auctioned in 2024 were fully subscribed, with a competitive tariff of INR 3.41 per unit (March 2024) and INR 3.52 per unit (July 2024). SECI’s CUF norms (non-peak hours) can be considered as the best practice measure.

DISCOMs issuing solar-plus-storage tenders should also specify the RTE and peak availability norms to ensure that power is available during the peak hours, when the grid needs it most.

Recommended Performance Parameters

Capacity Utilization Factor (CUF): A minimum CUF must be specified; an illustration for CUF computation to remove any ambiguity should also be included.

Round-Trip Efficiency (RTE): RTE should be specified at greater than or equal to 85 percent. RTE should not be treated as a stand-alone evaluation metric in tenders unless the charging power is also being supplied by the buyer.

Peak Availability: Peak availability should be mandated as at least 90 percent during defined peak hours; an illustration for computation (monthly and annually) to remove any ambiguity should also be included.

Risk Mitigation (Parameter 2)

PROJECT LOCATION AND PERMITS

Project siting is one of the most critical parameters in designing solar-plus-storage tenders. The location of a hybrid project impacts not only energy yield and cost efficiency but also grid integration, transmission costs, and project timelines.

Three sets of questions must be answered when deciding upon project location.

1. Location: Should solar and BESS be sited at different locations and linked through the grid? Alternatively, should solar and BESS projects be co-located at a renewable resource–rich site, or should they be near load centers to minimize transmission losses?

2. Land acquisition responsibility: Should the tendering agency pre-identify land parcels and allot them, or should developers acquire land independently?

3. Permits: Should the tender specify all necessary approvals to be obtained? Additionally, should the tenders detail the responsibilities of the various parties—e.g., project developers, and buyers or intermediaries—with respect to permits and approvals?

A locational study involving multi-criteria analysis of RE resources (e.g., solar irradiation for solar generation), land availability, grid requirements, and available grid infrastructure capacity (e.g., lines and substations) for power evacuation must be performed prior to determining site locations. The study’s findings will inform transmission and distribution plans, identifying areas where transmission infrastructure needs to be upgraded. For instance, the Australian government has pre-identified high renewable resource areas called renewable energy zones, which already host strong grid infrastructure and aggregated land for developers. The New South Wales Renewable Energy Zone framework offers land access agreements with guaranteed grid capacity. Because of its abundant industrial land and high irradiance, Castile-La Mancha in Spain has emerged as one of the most attractive regions for solar and hybrid project deployment, accounting for over 20 percent of national solar generation and hosting several large-scale solar complexes.

In 2014, the Indian government rolled out its Development of Solar Parks and Ultra-Mega Solar Power Projects scheme to address challenges related to land acquisition and the procuring of clearances and permits. Spurred by this scheme, the state of Madhya Pradesh launched its 2015 Ultra Mega Solar Power project in the city of Rewa, which won both the “Book of Innovation” award from the prime minister and the World Bank’s “President Award.” The provisions related to land pooling in particular represent best practices and should be replicated across the country. For the 750 MW solar project, the state government purchased private land under a mutual consent policy that ensured effective and timely land procurement for the project, contributing significantly to timely commissioning. As part of the tendering process, Rewa Ultra Mega Solar Limited (RUMSL) signed an implementation support agreement with the project developers to hand over the possession of the land for project development and took responsibility for providing necessary evacuation infrastructure up to the point of delivery. Based on this project’s success, the state government is now following the same process for its first solar-plus-storage tender to reduce developer risk, support faster commissioning, and determine a competitive tariff. The solar-plus-storage tender document also provides an initial list of necessary approvals, along with the party responsible for obtaining those approvals.

The state of Maharashtra’s land provision policy under “Mukhyamantri Saur Krushi Vahini Yojana”-2.0 (Chief Minister’s Solar Agriculture Feeder Scheme) (MSKVY 2.0) is another best practice example. MSEB Solar Agro Power Limited’s (MSAPL) tender conditions specified that MSAPL would lease government-owned land, which would be further subleased to developers at a nominal cost of INR 1 per hectare. In addition, MSAPL compiled a list of private land parcels available for lease in its portal and provided broad terms and conditions, such as base lease rent and lease tenure. This strategy benefitted project development by enabling improved transparency and minimizing land-related delays. MSAPL’s tender also provided a list of clearances and the government departments responsible for issuing them, further benefiting project developers.

While there is no predefined global best practice, based on the above-mentioned examples of solar-plus-storage projects and the cost-optimal pathway study of India, this report recommends conducting a locational study, setting up a project in high renewable resource areas, and designating pre-identified clusters to increase the chances of projects’ viability and success. To facilitate faster project deployment, local (state) authorities should provide support with land pooling and grid evacuation infrastructure, including purchasing land, making use of government-owned land for leasing and further subleasing, and compiling available private land parcels and pairing their leasing with terms and conditions for base rent, lease tenure, and other conditions.

Recommended Project Siting and Permitting

Conduct a locational study which includes multi-criteria analysis of RE resources (e.g., solar irradiation for solar generation), land availability, grid requirements, and available grid infrastructure capacity (e.g., lines and substations) for power evacuation.

Incorporate clear siting guidelines in tenders and provide facilitation measures such as land pooling, evacuation infrastructure, and a list of required approvals, thus de-risking the project, reducing uncertainty, and ensuring timely project completion.

As such, the tendering agency should:

1. Favor pre-identified land within solar parks or renewable energy zones for faster execution.

2. Include land pooling mechanisms with clear allotment processes in tender documents.

3. Publish GIS-based mapping of high-resource zones, land availability, and grid infrastructure for transparency.

4. Ensure implementation support agreements cover:

   • land possession;

   • permits and clearances; and

   • internal evacuation responsibility.

FINANCIAL RISKS AND INCENTIVES

Payment security mechanisms (PSMs) safeguard developers against the risk of delayed payment or non-payment by offtakers. PSMs also reduce offtaker risk, a major concern for the banks and investors financing long-term infrastructure projects. Finally, PSMs ensure payment certainty despite the financial instability of DISCOMs. A robust PSM boosts tender participation and leads to more competitive tariffs. The following delineate two recommended models for PSMs.

1. Letter of Credit: The buying entity provides a single, unconditional, revolving, and irrevocable letter of credit, which SECI in turn makes available to the project developer. With respect to the amount, SECI stipulates the following conditions for the buying entity:

   • The letter of credit shall have an amount equal to 110 percent of the estimated average monthly billing for the first contract year, and 110 percent of the average monthly tariff payments from the previous contract year for each subsequent year.

   • If the buying entity—i.e., the deemed distribution licensee—is not covered under the Implementation of the Electricity (Late Payment Surcharge and Related Matters) Rules (2022), the amounts become 210 percent, calculated as above.

   • If the buying entity is not covered by the state government guarantee (including within the Tri-Partite Agreement) or is unable to provide such a guarantee, the amounts become 210 percent of three times the estimated average monthly billing and, for subsequent years, 210 percent of three times the average monthly tariff payments from the previous contract year.

   • If the buying entity is not the deemed distribution licensee, the amounts become 210 percent of six times the estimated average monthly billing and, for subsequent years, 210 percent of six times the average monthly tariff payments from the previous contract year.

2. Payment Security Fund (PSF): SECI tenders provide project developers with the option of establishing a payment security fund. To build the fund, SECI asks project developers to provide a discount of INR 0.02 per kWh in the monthly billing, which is then apportioned to the PSF. Redeemed performance bank guarantees (PBGs) and payment on order instruments are also incorporated into the PSF.

The Electricity (Late Payment Surcharge and Related Matters) Rules (2022) mandate that DISCOMs maintain unconditional, irrevocable, and adequate payment security mechanisms. The Ministry of Power’s competitive bidding guidelines stipulate a letter of credit and a state government guarantee as payment security mechanisms (PSMs). For state DISCOMs issuing solar-plus-storage tenders, this paper recommends a three-tiered arrangement consisting of a letter of credit, either a payment security fund or an escrow account, and a sovereign (state government) guarantee to provide security against payment default.

Recommended Payment Security Mechanisms

A three-tiered PSM comprising a letter of credit, either a payment security fund or an escrow account, and a sovereign (state government) guarantee is best suited to boost tender participation and provide security against payment default by DISCOMs.

1. Letter of credit: The offtaker is responsible for this first tier of protection against default. The offtaker must set up and maintain an unconditional, revolving, and irrevocable letter of credit in favor of the developer.

2. Payment security fund or escrow account: Either the offtaker or a third party (preferably the tendering authority) is responsible for this second tier of protection and must maintain the fund; the corpus of such fund can be determined based on the credit rating of the offtaker.

3. Sovereign guarantee: The third and final tier of protection against default comprises a formal payment backstop issued by the state government. This provision should become operational only if the first two levels fail.

For tenders issued by REIAs, such as SECI, PSMs can be structured in a manner to reflect the DISCOMs’ credit ratings. Those with good ratings can be offered either an easing of terms and conditions for the opening letter of credit or a discount in trading margin.

PERFORMANCE INCENTIVIZATION

A performance bank guarantee (PBG) comprises the financial security deposit submitted by the winning bidder to ensure that they meet contractual obligations. The guidelines for tariff-based competitive bidding issued by the Ministry of Power mandate that the amount of PBG (not less than 5 percent of the estimated total capital cost of project) be incorporated into the tender document.

The MoP’s guidelines identify the instruments to be used for the PBG—bank guarantees or a payment on order instrument from the Indian Renewable Energy Development Agency (IREDA), the Power Finance Corporation Limited (PFC), or REC Limited (REC).

SECI-issued tenders are a third possible PBG instrument, issued in the form of an insurance surety bond by the Insurance Regulatory and Development Authority of India (IRDAI). Insurance-backed guarantees are a common practice in the developed economies of the United States and the European Union. Furthermore, these guarantees reduce the upfront capital blockage, which is helpful for developers.

Recommended Performance Incentivization

Solar-plus-storage tenders should allow use of all three instruments—bank guarantees; payment on order instruments from IREDA, the PFC, or REC; and insurance surety bonds issued by IRDAI.

POWER OFFTAKE ARRANGEMENTS

The power offtake arrangement between the project developer and the buyer influences project viability. For risk mitigation, key aspects of the power offtake arrangements should be included in the tender design:

1. differentiation between peak supply only and peak and off-peak power supply;

2. excess power procurement;

3. approved partial or early commissioning;

4. compensation for curtailed generation; and

5. energy shortfall penalties.

Solar-plus-storage (2–4 hours) projects are intended to store cheap solar power collected during the daytime and then discharge said stored power during peak hours (evening and morning). Because of this, buyers are primarily concerned with procuring power during peak hours. The SECI solar-plus-storage tenders do not ask the bidders to quote separate tariffs for peak and non-peak hours, only specifying what are considered peak and non-peak hours. While the SECI’s solar-plus-storage tenders have competitive tariffs, its peak hour tender resulted in a high tariff of INR 8.5 per kWh, largely due to risk-hedging, as the developers factored all associated costs into those peak hours of supply which otherwise would have been spread over a greater number of hours. Therefore, price-sensitive buyers such as DISCOMs should opt for a single tariff for peak and non-peak hour supply.

To meet the stipulated power requirements and avoid penalties, developers may oversize the project capacity. This can result in instances when solar-plus-storage projects generate excess power vis-à-vis contracted capacity. Buyers could procure excess solar energy at a mutually agreed upon discounted tariff, potentially pegged to the lowest solar tariff from the previous year, disincentivizing excess generation. Alternatively, to allow optimization of energy storage, the project developer could be allowed to sell excess generation to a third party or through a power exchange during non-high-demand hours. As an additional risk mitigation measure, the project developer could be allowed to source 5 percent of renewable power (in energy terms) on an annual basis from green market sources or other bilateral arrangements in order to meet supply commitments.

Furthermore, tender documents could allow for partial or early commissioning of the generation asset. To avail developers of the full benefits of solar-plus-storage systems, tenders could specify a minimum capacity for solar PV and BESS at which the project could qualify for partial or early commissioning. Alternatively, the tender documents could allow project developers to sell the power generated from a partially or early commissioned project to a third party or through a power exchange until commercial operations begin.

To compensate the project developer when the generation is curtailed due to grid unavailability, force majeure, or transmission delay, the tender document should provide a methodology or compensation framework, reducing investor risk. The tender document should also provide for compensation when it can supply power, but the offtake is not done by the buyer; this would include the non-dispatching of power due to noncompliance with the late payment surcharge rules.

If reduced offtake is due solely to the buyer, the developer should not be asked to adjust to 95 percent of the payable compensation. In fact, such a provision could disincentivize the project developer from selling that power in the market. To balance the financial interests of DISCOMs and project developers, and to promote better planning, tender-issuing entities should explore the implications of reducing the adjustment to 90 percent.

▲ Table 12: Ministry of Power Guidelines on Compensation Mechanisms. Source: 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,”.

Ensuring that solar-plus-storage projects deliver contracted energy during both peak and non-peak hours is critical for maintaining grid reliability and protecting consumers. Any shortfall in supply forces the buyer to procure costly backup power, undermining the economic rationale of the project. Clear mechanisms for addressing energy shortfalls through penalties or compensation create a strong incentive for developers to size systems appropriately, to manage storage degradation responsibly, and to maintain operational discipline throughout the contract period. The SECI solar-plus-storage tenders’ penalty mechanism differentiates between peak and non-peak energy shortfalls. The penalty for peak hours is calculated in relation to the actual energy (in million units) to be supplied, while for non-peak hours the penalty is measured against the CUF requirements. The penalty is calculated using the tariff payable to the project developer by the buyer. This report recommends that for any future solar-plus-storage tenders in India, depending upon the buyer’s preference, the penalty could be applicable for either energy shortfalls during peak hours only or energy shortfalls during peak and non-peak hours. The buyer could even opt for applying the PPA tariff for the purpose of calculating penalties. If the buyer chooses to apply a penalty only for energy shortfall during peak hours, instead of applying the PPA tariff, the buyer could opt for a stricter measure, that is, either a tariff higher than the PPA tariff or at the level of the system’s marginal cost to reflect the true cost of replacement power to the system.

Recommended Power Offtake Arrangement

Within the tender document, the following must be clearly stipulated:

1. a single, defined tariff for peak and off-peak hours;

2. excess solar energy procured either at a mutually agreed discounted tariff or allowed to be sold to a third party or in a power exchange during off-peak hours;

3. allowance for partial and early commissioning;

4. compensation for curtailed power generation due to grid unavailability, force majeure, or transmission delay, with specifications for buyer-driven curtailment; and

5. provision of a penalty application mechanism for situations of energy supply shortfalls in peak and non-peak hours, preferably based on the applicable PPA tariff for transparency and predictability.

BUSINESS MODELS

Selecting the appropriate business model for solar-plus-storage projects is critical to ensuring financial viability, risk allocation, and long-term operability. The business model defines how the project will be monetized, who will bear capital and operational risks, how revenues will be structured, and which contractual frameworks (e.g., PPA, tolling, market-based) will govern interactions. Common business models include the following:

1. Build-Own-Operate (BOO) or Build-Own-Operate Transfer (BOOT): In the BOO model, the private developer designs, finances, builds, owns, and operates the solar-plus-storage asset. Revenue is earned through long-term PPAs or availability-based contracts, with the developer retaining asset ownership beyond the contract term, allowing for salvage value recovery and possible repowering. In BOOT models, similar to BOO, the developer assumes full capital and operational risk but transfers the asset to the procurer at the end of the contractual period. Public utilities and government agencies that ultimately seek asset ownership prefer the BOOT model.

2. Engineering, Procurement, and Construction (EPC): Under the EPC model, the contractor is responsible for the design, procurement, construction, and commissioning of the solar-plus-storage system on a turn-key basis. The procuring utility or agency funds the project and retains ownership and long-term operational responsibility.

3. Energy-as-a-Service (EaaS) or Storage-as-a-Service: These performance-based models entail the end-user paying for a service—such as availability, delivered energy, or peak capacity—without owning the asset. The private provider installs, operates, and maintains the system while charging fees based on pre-defined performance metrics.

4. Tolling/Hybrid Merchant: Under this model, the buyer (often a utility) pays a set fee to the project developer of a solar-plus-storage project to rent the project’s capacity, controlling its dispatch and assuming related risks. The project developer retains responsibility for the project’s operation and maintenance.

Recommended Business Model

In India, for any greenfield solar-plus-storage project, the build-own-operate (BOO) model is preferred, as it enables long-term private sector involvement and allows developers to recover residual asset value, leading to more competitive tariff discovery and reduced lifecycle costs.

Storage and System Operations (Parameter 3)

BESS CHARGING AND DISCHARGING

To strategically discharge storage to meet peak demand with stored solar power, this report recommends that the offtaker controls the discharge of BESS during peak hours. During off-peak hours, discharge could be under the project developer’s control, allowing operational flexibility and potential revenue optimization from third-party sales or arbitrage. The charging of BESS shall be done by the project developer and only through solar power for DC-coupled systems. For AC-coupled systems, the tender could allow grid charging under clearly defined conditions (e.g., on low solar days, at a capped cost) to ensure evening peak availability and reliability. To discourage undercharging batteries and underutilization of storage assets, tenders should specify a minimum solar generation or project CUF (≥ 17 percent), measured on a monthly basis. These safeguards protect against excessive reliance on grid charging and ensure that solar energy is the primary input.

LIMITED DAILY CYCLING OF BESS

There is no defined standard for daily limits on BESS cycling. The recommended best practice for optimizing battery life and maximizing grid value is to charge the batteries with low-cost solar energy during the period of excess solar generation and discharge it during peak demand period.

PEAK HOUR DEFINITION AND AVAILABILITY

There is no defined best practice on peak hour definitions. In California and Hawai’i, utilities require that the generation asset be available between 5 and 10 PM. SECI tenders in India allow the buying entity to define the hours during which it intends to draw energy from the BESS on a day-ahead basis. The Madhya Pradesh Morena solar-plus-storage tender defines peak hours as morning 6–9 AM and 6–10 PM; most utilities in India have similar peak hours.

Peak availability should be measured on a monthly basis with minimal tolerance in the demand-fulfillment ratio. Several recent solar-plus-storage tenders in India require 90–95 percent availability during peak demand periods, measured monthly and/or annually.

Clearly defined peak hours and corresponding demand-fulfillment ratios will significantly influence project configuration, particularly for solar-plus-BESS systems. For instance, meeting evening or night peak demand requires a larger storage capacity than meeting morning peaks, as developers can directly utilize solar generation to serve morning demand. In contrast, evening peaks (typically 7–11 PM) occur after sunset, necessitating sufficient storage to shift solar energy from earlier in the day. Therefore, to ensure adequate storage deployment, evening hours should always be designated as peak hours, alongside morning peaks when necessary, based on utility load profiles and system needs.

Recommended Storage and System Operations

1. Offtaker control over BESS discharge during peak hours

2. BESS charging only through solar power for DC-coupled connected systems; grid charging potentially allowed under clearly defined conditions

3. Undercharging of batteries and underutilization of storage assets discouraged via required minimum solar generation levels or project CUFs, measured on a monthly basis

4. Optimized battery life and maximized grid value through batteries charging via low-cost solar energy during excess solar generation periods and energy discharging during peak demand

5. Peak availability measured on a monthly basis, with minimal tolerance in demand-fulfillment ratio

6. Evening hours always designated as peak hours, alongside morning peaks when necessary, based on utility load profiles and system needs

California Case Study

Energy Landscape

Historically, California has been the leader in renewable energy in the United States both in terms of policy ambition and deployed capacity. In 2025, California possesses roughly 6 GW of wind energy, 23 GW of solar energy, and 16 GW of energy storage capacity. In 2024, renewables—including a large base of hydroelectric developed in the twentieth century—represented 51 percent of all power generation in the state.

Storage has rapidly emerged as a major component of the California electric power sector. The installed capacity grew from a mere 0.5 GW in 2019 to 16 GW as of April 2025. Upward of 8 GW of additional storage capacity is in various stages of construction or planning. As of June 2025, the peak recorded storage discharge in the California power market stood at 10.8 GW.

The California electric power system is organized around a single independent system operator (ISO)—the California ISO (CAISO)—which acts as the balancing authority, market administrator, and centralized financial intermediary between supply and load participants. CAISO has dispatch authority over all utility-scale generation assets operating within its footprint. Dispatch schedules are determined through competitively structured day-ahead, real-time, and ancillary services markets.

California has several major integrated utilities that service the majority of the load. The state allows some alternative retail suppliers to participate, most notably in the format of community choice aggregations, which effectively operate as municipal retailers for residential and small commercial customers. Collectively, these entities are referred to as load-serving entities (LSEs) and fall under the jurisdiction of the California Public Utilities Commission (CPUC) policy mechanisms described next.

Policy Targets and Mechanisms

The California state government has established a planning target of 100 percent zero-carbon energy by 2045 for the electric power sector. The state is pursuing this target through three primary mechanisms.

First, a renewable portfolio standard (RPS) provides LSEs with individual renewable energy certificate (REC) procurement targets for each year; RPS accounting is done on an annual basis, meaning that an LSE has no requirement to match REC procurement to an hourly load profile. Annual procurement targets are set for four-year periods and are defined as a percentage of load served. For the 2020–2024 period, the procurement target is 44 percent; the next four-year period’s target increases to 52 percent.

Second, the CPUC administers an integrated resource planning (IRP) process that oversees and directs the procurement of new resources by the state’s LSEs. The IRP process determines required capacity procurement volumes in line with state targets, in a least-cost manner and while preserving overall resource adequacy and system reliability. Over the multiyear IRP process, LSEs submit resource procurement proposals to the CPUC. These proposals are then reviewed; stakeholder comments are solicited; proposals are altered, if necessary; and proposals are confirmed as binding orders by the CPUC. The most recent cycle, finalized in February of 2024, ordered an additional 19 GW of solar, 15.7 GW of four-hour lithium-ion batteries, 2.8 GW of eight-hour lithium-ion batteries, 0.5 GW of long-duration storage, and 4.5 GW of offshore wind by 2035.

Third, the CPUC administers a resource adequacy (RA) program, which functions similarly to capacity markets operated in other U.S. power markets. Under this program, the CPUC orders California LSEs to procure sufficient (defined) capacity on a forward basis equivalent to their forecasted peak demands for upcoming years. This program is a key driver of storage deployment because it creates demand for the RA volume (in MW) of a battery project. Furthermore, the program creates a secondary revenue stream for storage assets beyond the energy value of the project, improving the financial viability of projects.

California Procurement Practices

The combined effects of these policy mechanisms are large volumes of renewable and battery storage capacity deployment. The RPS, IRP, and RA policy mechanisms mandate procurement volumes, while granting considerable leeway to LSEs on the exact specifications and configurations of resource procurement. This allows LSEs room to procure necessary resources in whatever configuration is most beneficial to their portfolios and lowest cost for developers to deliver.

For example, the IRP process mandates large volumes of renewables and storage procurement but includes no requirement to directly connect renewable generation with storage resources. Eventually, of course, variable renewable output must be balanced with storage and other generation resources, but this is CAISO’s responsibility in its role as the balancing authority through normal market dispatch procedures.

Resource procurement through public request for offers (RFOs) proceedings is conducted exclusively by offtaking LSEs. In California, RFOs are typically structured with topline volume targets, which can be met through several project types and technologies, including stand-alone renewables, stand-alone storage, and various types of hybrid configurations. RFOs can be structured to procure energy, meaning actual electrical volumes in MWhs, for example, as well as REC volumes for RPS target compliance and resource adequacy volumes to meet that program’s compliance targets. The table below, from a 2023 PG&E RFO, is typical of this structure.

▲ Table 13: California PG&E Midterm Reliability Tender Requirements. Source: “Mid-term Reliability Request for Offers Phase 3 Solicitation Protocol,” PG&E, February 7, 2023.

For each resource category, PG&E offers different contract models and provides, ahead of time, pro-forma contract templates to project developers. This RFO model creates considerable flexibility for both developers and utilities in terms of technology, configuration, and contract model. Additionally, this model allows developers to bring the highest-value options to the RFO. For the utility itself, which faces a complex array of procurement mandates, this flexibility ensures that least-cost solutions are brought to the table.

Storage-Contracting Models

The most common format for battery storage offtake in California is a long-term resource adequacy agreement (LTRAA) or its variation, LTRAA with energy services (ES). These contracts center on the RA that a storage project provides to an LSE by establishing a fixed price, in $kw per month, for the defined RA volume over time. The project developer retains ownership and market participation authority over the asset, meaning that they are free to monetize the storage assets through participation in ancillary services or energy markets. The ES option centers on whether the price risk of daily charging is held by the offtaker or the asset owner, effectively giving the developer a choice of more or less revenue certainty.

In select cases, California’s large integrated utilities have entered into build-own-transfer or EPC agreements for battery storage, in which the utility takes ownership and operational control over the storage asset. In the wake of 2020 bulk power system failures, the CPUC approved 500 MW of EPC contracts for battery storage, prioritizing urgency over economic efficiency for capacity additions, a heavily protested decision. As the storage development market has matured, EPC contracts have become less necessary and increasingly uncommon.

In California and elsewhere in the United States, the tolling contract model has emerged as an offtake solution for storage resources. The model is also becoming more common in Texas, which is rapidly overtaking California as the largest battery market in the United States. As of March 2025, Texas had seen over 5 GW of storage capacity deployed, with another 8 GW expected by 2026. As Texas has no capacity mechanism akin to California’s resource adequacy program, the LTRAA contract is not applicable.

In a tolling contract, the utility (the offtaker) pays a fixed monthly fee (rent) that grants it operational control over the battery storage unit (i.e., charge and discharge, market participation). Meanwhile, the project owner (the toller) retains ownership and assumes maintenance responsibilities for the facility, while the asset owner is provided with the long-term revenue certainty necessary to secure a final investment decision from financing partners and commence construction. Finally, for the offtaker, the tolling contract model grants maximum flexibility to optimize battery operations relative to their portfolios. On the other hand, the offtaker assumes all market risk and must ensure that it monetizes the battery storage unit above the fixed costs of the contract.

Storage Economics

The overall state of battery storage economics in California is well captured by CAISO’s 2023 Special Report on Battery Storage. The data reveal that a large portion of battery storage in California is physically sited alongside other renewable projects (as hybrid or co-located systems). Despite this, the vast majority of storage is contracted and dispatched, participating in the market as independent generation resources (stand-alone or co-located).

The successful storage deployments in California and Texas rely on market structures that create opportunities in which batteries—with their ability to provide myriad services to the energy grid—enable multiple value streams. Within the markets of both states, procurement practices and contracts have developed that enable the realization and monetization of this capacity. CAISO data from 2022 to 2023 shows that revenue from battery storage is spread across multiple services beyond energy arbitrage, including regulation up and down and real-time bid-cost recovery. However, CAISO data does not account for climbing resource-adequacy contract revenues from rapidly increasing RA prices. The surge in pricing for RA volumes is the result of a tight RA market driven by thermal generation resource retirements, load forecast increases, and changes in RA accounting that, combined, have reduced the RA value of renewable resources. Battery storage resources are effectively the only new resource capable of filling the RA market need, as well as the broader system need for new dispatchable generation. Overall, achieving California’s ambitious goal of 100 percent zero-carbon energy by 2045 will require ongoing innovation in both policy and procurement processes to enable investment in storage resources that support variable renewable energy sources. So far, California is a leader in this field, as its policy has enabled a dynamic developer ecosystem, with flexible procurement and configuration standards, as well as clear price signals. This case study indicates that these principles are key to scaling deployment of high-value storage systems at low system cost.

Lessons from California

INTEGRATED RESOURCE PLANNING SHOULD DETERMINE UTILITY PROCUREMENT TARGETS

Regular, rigorous, and transparent integrated resource planning (IRP) processes should determine procurement strategies. The IRP-process outputs should be used as the inputs that define the shape and scope of a utility procurement cycle. The IRP system can give a clear indication of technology requirements, siting needs (e.g., regional, load-zone, or node level), commercial operation date timelines, and expected dispatch requirements. Tendering design and timelines should then be modeled on these findings.

Increasing the penetration of variable renewable energy resources and the introduction of two-way resources such as battery storage represent a step-change in system complexity. Sophisticated and regular modeling of evolving technology options, cost profiles, and system demand are needed more than ever. The larger the scope of an IRP, the more valuable it is to the system; California’s IRP process synthesizes the individual resource plans and system models of many different utilities and defines a path for the system as a whole, allowing for lower costs and more reliable solutions.

Moreover, because the IRP process can produce system needs over short-, medium-, and long-term horizons, they act as a clear signal for developers about the likely demand for projects.

In 2023, the Indian MoP issued guidelines for DISCOMs to adopt 10-year resource adequacy (RA) plans. These RA plans should serve as the guiding documents for utility procurement targets. The REIAs should leverage RA plans to release exclusive tenders for the different states and DISCOMs, ensuring optimal procured RE and storage capacity as well as alignment with grid requirements, thus enhancing grid reliability and accelerating the energy transition. Furthermore, this strategy reduces offtaker risk, as tenders are issued according to DISCOMs’ specific requirements, addressing challenges seen in some existing tenders.

FLEXIBLE STORAGE AND RENEWABLE CONFIGURATIONS

Both high-level procurement targets and specific tendering processes should create flexibility regarding renewable and storage pairing configurations. At a high level, the two technologies are complementary; large volumes of storage are needed to resolve the intermittent profile of variable renewable energy. At the granular level of project development, resource procurement, and resource dispatch, there are multiple possible configurations for these technologies. Different solutions will be optimal at different times and for different markets. Procurement models should grant flexibility to both the offtaking entity (e.g., a local DISCOM) and the project developer to bring forward the best solution.

In California, stand-alone and co-location solutions are currently preferred. By creating an RFO process and offering contracts that allow for all possible configurations, market participants have been able to develop high-value solutions and rapidly scale battery storage deployment. The market preferences in California are shifting toward hybrid configurations (co-located solar-plus-storage). For example, solar curtailment rates are rapidly rising, increasing the value of storage configured as a hybrid resource. The current flexible procurement model will allow this solution to come to the fore if and when market participants identify it as valuable.

INTRODUCING MULTIPLE VALUE STREAMS

Policymakers should consider mechanisms that monetize specific system contributions available via storage (and other resources), including capacity market (resource adequacy) and ancillary service mechanisms.

Battery storage is a uniquely flexible resource, able to provide many different services. In California and Texas (as well as in European markets), access to these non-energy markets is a key revenue source, helping improve battery storage economics. Moreover, battery storage often provides initial value in providing ancillary services at far lower cost than thermal resources, thus reducing load costs. After this initial value, battery storage can provide value by engaging in intra-day energy balancing, specifically, by charging at peak solar output hours and discharging at peak net-load hours. Storage can also provide rapid-response reserve services and has proven valuable in mitigating risks during steep evening net-load ramps.

Conclusion

India’s ambitious clean energy journey hinges on rapid and large-scale deployment of energy storage systems, and especially BESS, to enable reliable integration of variable renewables. Internationally, pairing solar generation with battery energy storage has proven to be one of the fastest and most effective ways to accelerate storage deployment. International experiences reveal pairing solar with storage, through thoughtful tender design and market mechanisms, can unlock investment and operational efficiencies for power systems.

India, by contrast, has struggled to gain similar traction despite ambitious targets. With 0.11 GW of operational BESS as of 2024 against a projected requirement of more than 73.93 GW by FY 2031–32, the gap is stark. Key reasons include the absence of clear storage procurement mandates, tendering focused narrowly on renewable energy capacity instead of dispatchable power, and uncertainty around cost recovery, payment security, and performance obligations. DISCOMs have often adopted a “wait-and-watch” approach, hesitant to sign long-term contracts in a rapidly evolving technology and tariff environment. This lack of coordinated planning and tendering mechanisms has delayed investment decisions, increased financing costs, and slowed down the pace of energy storage adoption at utility scale. However, on a positive note, since 2024, several major stand-alone BESS tenders have been awarded or are in the process of being awarded in India under the Viability Gap Funding (VGF) scheme (tranche 1 and 2).

This report puts forward an actionable solar-plus-storage tendering playbook to address India’s deployment challenges and catalyze ESS growth. Drawing on international best practice and cost-optimal modeling, the playbook recommends:

• Explicit technology pairing (solar-plus-BESS), clear minimum sizing (≥0.5 MW/1 MWh per MW solar), and defined storage duration norms (2–4 hours) in tenders.

• Flexible coupling configurations, with project design optimizing AC/DC coupling choice for efficiency and resilience.

• Transparent project siting, supported by locational studies, pre-identified zones, land pooling, and GIS mapping to speed implementation and cut risks.

• Robust risk mitigation mechanisms including tiered payment securities (letter of credit, escrow, sovereign guarantee), diversified performance bonds, and flexible power offtake terms (including partial commissioning and market access for excess solar).

• Clearly defined operational metrics, such as capacity utilization factor, round-trip efficiency, and peak availability, to assure system reliability and developer accountability.

• Alignment with utilities’ resource adequacy planning.

By focusing on these elements, the playbook equips policymakers, utilities, and developers with practical, scalable tools to unlock investment and accelerate BESS deployment, ensuring that energy storage is no longer a bottleneck but a strategic enabler of India’s 500 GW clean energy ambition. Adopting this framework will not only drive competitive tariff discovery and reduce procurement costs but also deliver grid flexibility and resilience. A solar-plus-storage system can deliver 24 x 7 clean power at over 95 percent availability for less than 6 INR/kWh.

Appendix 1

Impact of Solar-Plus-Storage on APPC

The national and state-level modeling presented in this report demonstrates that solar-plus-storage integration places strong downward pressure on the average power procurement cost (APPC). Figure A1 illustrates how, despite significant capacity additions, procurement costs are projected to decline by 5–10 percent when compared to 2024 levels.

▲ Figure A1-1: Solar-Plus-Storage Impact on Average Power Procurement Cost (APPC). Source: Authors’ analysis.

Appendix 2

Subnational Cost-Optimal Pathways

This section presents the findings of the least-cost modeling study for five states—Maharashtra, Madhya Pradesh, Andhra Pradesh, Karnataka, and Tamil Nadu—in order to identify the most cost-effective and technically viable mix of generation and storage resources to ensure reliable electricity supply by FY 2031–32. The modeling framework accounts for key constraints—including renewable purchase obligations, reliability standards, spinning reserve requirements, and resource availability—thereby offering actionable insights to inform policymakers, utilities, and energy planners in shaping future investments and policies.

The analysis draws on detailed data, including unit-wise contracted capacities, energy availability, fixed and variable costs (sourced from state tariff orders for FY 2021–22 through FY 2024–25), as well as information on retiring plants, expiring power purchase agreements (PPAs), and upcoming projects. FY 2023–24 is the base year and FY 2031–32 is the target year, with costs projected based on historical trends and estimated future energy requirements as per the 20th Electric Power Survey for each state.

The study includes long-term capacity expansion from the FY 2023–24 baseline to the FY 2031–32 target, along with a detailed production cost analysis for FY 2031–32. The results include a summary of recommended new capacity additions across the five states. Notably, the short-term dispatch simulation for FY 2031–32 revealed a reduction in average power purchase costs compared to FY 2023–24, highlighting potential economic benefits of the optimized generation mix.

Across the states studied—Maharashtra, Madhya Pradesh, Andhra Pradesh, Karnataka, and Tamil Nadu—a common trend emerged: The least-cost pathways to FY 2031–32 consistently prioritize large-scale solar PV deployment, supported by a robust mix of two- and four-hour battery storage to ensure grid reliability and flexibility. The modeling results highlight the strategic importance of storage in balancing renewable variability, meeting peak demand, and reducing average power-purchase costs. These insights underscore the need for integrated planning, proactive policy support, and timely infrastructure development to realize a secure and sustainable energy transition across the southern and central Indian power systems.

Maharashtra

Generation expansion modeling for Maharashtra envisions 80,358 MW of new capacity, including battery storage—2,035 MW (two-hour) and 12,000 MW (four-hour). Solar PV leads with 48,187 MW, supported by wind (8,165 MW) and distributed RE (9,971 MW).

▲ Figure A2-1: Generation Expansion Modeling Results for Maharashtra, FY 2023–24 to FY 2031–32. Source: Derived from authors’ modeling using GridPath energy modeling software.

Madhya Pradesh

The FY 2031–32 generation expansion plan for Madhya Pradesh adds 45,249 MW of new capacity, aiming for a total installed capacity of 70,984 MW. To support renewable integration and grid flexibility, the plan includes significant battery storage: 531 MW/1,062 MWh of two-hour systems for short-term balancing and 10,000 MW/40,000 MWh of four-hour systems to meet peak demand and ensure system reliability, reflecting the state’s commitment to a sustainable energy future.

▲ Figure A2-2: Generation Expansion Modeling Results for Madhya Pradesh, FY 2023–24 to FY 2031–32. Source: Derived from authors’ modeling using GridPath energy modeling software.

Andhra Pradesh

The FY 2031–32 capacity expansion modeling for Andhra Pradesh proposes 65,774 MW of new generation and 69,438 MWh of additional storage to meet growing demand while supporting a clean energy transition. The storage mix includes two-hour and four-hour battery systems, alongside six-hour pumped hydro, ensuring grid flexibility and reliable renewable integration.

▲ Figure A2-3: Generation Expansion Modeling Results for Andhra Pradesh, FY 2023–24 to FY 2031–32. Source: Derived from authors’ modeling using GridPath energy modeling software.

Karnataka

As part of Karnataka’s generation expansion planning for FY 2031–32, the model proposes 29,102 MW of new capacity, including 16,821 MW of solar PV, 4,364 MW of distributed RE, and 7,917 MW of four-hour battery storage (31,668 MWh).

▲ Figure A2-4: Generation Expansion Modeling Results for Karnataka, FY 2023–24 to FY 2031–32. Source: Derived from authors’ modeling using GridPath energy modeling software.

The capacity expansion modeling for FY 2031–32 proposes 31,570 MW of new capacity, including 11,238 MW of solar PV, 6,085 MW of distributed RE, 5,000 MW of wind, 6,803 MW of four-hour battery storage, and 2,444 MW of two-hour battery storage, strengthening renewable integration and system reliability.

Tamil Nadu

▲ Figure A2-5: Generation Expansion Modeling Results for Tamil Nadu, FY 2023–24 to FY 2031–32. Source: Derived from authors’ modeling using GridPath energy modeling software.

Shashwat Kumar is a fellow with the Chair on India and Emerging Asia Economics at the Center for Strategic and International Studies. In this role, he leads the chair’s energy and climate projects and works closely with Indian states to strengthen U.S.-India relations on energy and climate. For the past 10 years he has been working on the energy policies of Indian states. As a practitioner, he has the direct experience of working with stakeholders on important regulatory matters such as tariff design, competition, and licensing. As an academic, he has extensively researched and published on the Indian electricity sector.

Ammu Susanna Jacob is a research scientist and leads the Energy Storage Group at the Center for Study of Science, Technology, and Policy (CSTEP). At CSTEP, she focuses on various projects, including least-cost modeling for different states and utilities, sizing energy storage within the power grid, developing pricing mechanisms for storage, providing round-the-clock (RTC) renewable support through co-located storage, assessing the techno-economics of storage applications, and exploring the second-life use of electric vehicle batteries in grid applications. Her broader research interests encompass renewable energy integration, energy storage, microgrids, and policy frameworks for sustainable and resilient power systems.

Nikit Abhyankar is a scientist in the Energy Markets and Policy Department at the Lawrence Berkeley National Laboratory (LBNL). He is also an affiliate senior scientist at the Goldman School of Public Policy, University of California, Berkeley. He also serves as a guest faculty for the executive education program at University of California, Berkeley. Nikit has conducted extensive research and policy analysis on a range of key energy issues such as renewable energy, energy efficiency, electric vehicles, and energy access in the United States and key emerging economies such as India, China, Indonesia, and Vietnam. He regularly advises national and state governments, regulators, and utilities on designing clean energy policies and programs.