For years, the conversation around battery energy storage systems (BESS) – where there even was one – was limited to developers and grid operators. That is changing. The more important shift is economic rather than technological, with storage beginning to look like the kind of infrastructure asset institutional capital can underwrite.

Between 2010 and 2024, the total installed cost of battery energy storage fell by 93% to USD 197 per kilowatt-hour, while in 2025 alone, turnkey system prices dropped a further 30%, reaching their lowest recorded level.¹ This represents a structural repricing of what it costs to make renewable power reliable.

When batteries were expensive, pairing them with solar or wind was a luxury. Now it is rapidly becoming the default configuration. Co-located solar and storage deployment grew at approximately 70% per year between 2020 and 2025 and now accounts for roughly one in four such storage facilities with new utility-scale solar plants.

The consequence is financial as much as operational: storage can turn variable renewable output into a more underwritable revenue stream.

From Intermittency to Firm Power

Intermittency is not only a reliability issue. In markets with high renewable penetration, simultaneous generation can depress wholesale prices and erode project returns, a cannibalisation effect increasingly visible in the growing incidence of negative power prices.

Germany recorded 573 hours of negative prices last year, while Spain saw such hours double and France logged more than 500.²

Batteries address this constraint in a measurable way. By storing excess generation during periods of oversupply and discharging during peak demand, a co-located project may allow energy generated during periods of oversupply to be stored and discharged during periods of higher demand, potentially improving revenue capture, smoothing the output profile, and mitigating some effects of intermittency. Utilities are incorporating batteries in their integrated resource plans to manage grid stability and bridge the gap between peak demand and renewable energy generation. For example, certain utilities in California are offering 15–20-year resource adequacy contracts to meet state grid reliability rules.

The International Renewable Energy Agency's (IRENA) 2026 report introduces “firm levelised cost of electricity” (LCOE),³ which includes the storage and overbuild needed to deliver power at a specified reliability target. For investors, it is a more useful measure than plant-level generation cost because it captures the cost of usable electricity.

The decline in firm renewable costs has been sharp. IRENA modelling across multiple countries shows that firm LCOEs for solar-plus-battery configurations fell by nearly half over five years to roughly USD 54–82 per megawatt-hour by 2025 in high-irradiance regions. Further reductions of approximately 40% by 2035 are projected under current technology assumptions, bringing firm costs below USD 50 per megawatt-hour at the best-performing sites. China currently defines the global cost floor: simulations of 252 utility-scale solar projects commissioned in 2024 show minimum firm LCOEs as low as USD 30 per megawatt-hour at a 90% reliability level.

In some markets, that is already below the cost of new fossil-fuel generation, with US combined-cycle gas at about USD 102/MWh and new Chinese coal typically at USD 70-85/MWh.

The speed at which new capacity can be added may be an important consideration for allocators. In many cases, hybrid renewable systems may be developed and commissioned within one to two years, while new gas-fired generation projects can face longer development timelines, which may extend to five to seven years in certain markets due to factors such as supply chain constraints and increased turbine demand.

The Financing Transition

Cost competitiveness is only the starting point. For institutional capital, the central question is whether revenue can be contracted for long enough to support 15- or 20-year financing.

Early battery projects relied heavily on merchant arbitrage between low- and high-price hours, creating cash-flow volatility that limited appetite for long-dated, fixed-rate debt.

The shift now underway is towards contracted and tolling structures. Power purchase agreements with utilities and corporate offtakers, particularly hyperscalers and data centres seeking verifiable 24/7 clean electricity,  can provide the revenue certainty which may support long duration capital investment.

Regulation is reinforcing the shift. EU hydrogen rules will require hourly matching from 2030, while proposed changes to Scope 2 emissions accounting would make hourly and location-matched certificates more important for market-based claims. These frameworks create price signals that favour storage-integrated assets.

Currently, project finance banks continue to dominate BESS construction-phase lending. But as projects move into operation and performance data accumulates, a pipeline of post-construction refinancing opportunities is forming. This is the natural entry point for institutional investors seeking de-risked, income-producing assets with long contracted tenors. Investment in BESS solutions is expected to cross the USD 100 billion mark in 2026, according to the 2026 World Energy Investment Report.⁴

No investment thesis is complete without a detailed assessment of potential risks, and several deserve attention.

Duration remains a constraint. Most utility-scale lithium-ion systems provide up to around four hours of power, enough for intra-day balancing but not for multi-day weather events or seasonal gaps. Co-located BESS therefore manages intermittency risk rather than eliminating it.

Cannibalisation is another risk. If every solar project adds storage, peak-price windows may become crowded, compressing the spreads that justify the investment.

The third is that the concentration of cell manufacturing in China has made Foreign Entity of Concern (FEOC)/Supercritical Fluid Extraction (SFE) compliance under the One Big Beautiful Bill Act (OBBBA) one of the most consequential new variables in BESS underwriting in the US, particularly for projects starting construction in 2026, where at least 55% of manufactured-product cost must sit outside prohibited foreign entities to preserve the tax credits.

Finally, there is the maturity of performance data. While operational experience is growing and early results are encouraging, the empirical record for utility-scale BESS over a 15- to 20-year horizon remains limited. Degradation profiles, replacement cycles and long-term maintenance costs are still being validated. Prudent underwriting requires granular attention to contractual framework, operating conditions and manufacturer support through warranties and operating agreements.

Investing at Scale

Falling costs, longer-dated contracts and better operating data are turning co-located renewable-plus-storage from a technical innovation into an institutional asset class.

The opportunity, however, will depend less on simple exposure to a growth theme than on market selection, contracting strategy and underwriting discipline. The next phase is likely to produce wide dispersion in outcomes. Pairing storage with renewables is no longer about making green power work. It is about making it investable at scale.

PGIM Contributors

John Ploeg, Co-Head of ESG Research

Jacquelin Renda, Director

Ingrida Soldatova, Executive Director

Ty Bowman, Managing Director

Jean Erazo, Senior Investment Associate