Modeled Utility-Scale Solar+Storage Operations 2020-2024

In this project, we model optimized hourly dispatch under energy, capacity, and ancillary-service market opportunities using a linear optimizer with perfect price and generation foresight and are sharing the hourly solar and storage generation profiles for our sample here using the base scenario.

Large-scale (1MW+) co-located solar and battery storage projects are expanding rapidly in the United States, but their realized contribution to the bulk power system remains poorly understood because public project-level operating data are limited. The Lawrence Berkeley National Laboratory estimates the wholesale market value of 280 operational photovoltaic-plus-storage (PV+S) projects across the seven ISOs/RTOs and 19 additional balancing authorities, representing roughly 95% of the U.S. PV+S fleet in 2024.

In the full briefing compare the modeled optimized wholesale market value with the value of standalone PV, project-specific levelized cost estimates, and empirical operating or revenue data where available. Under optimized dispatch with perfect price foresight, adding batteries could have increased the national generation-weighted market value of solar from $29/MWh to $75/MWh in 2024, primarily through higher capacity value, followed by ancillary-service and energy shifting revenue. For projects with available cost data, optimized PV+S market value exceeded levelized generation cost by nearly $35/MWh from 2020-2024 when accounting for tax credits. Empirical operations of 51 projects captured substantial but incomplete value: in 2024, observed PV+S operations realized $39/MWh, or 62% of modeled optimized value, with the storage premium reaching only 38% of its optimized potential.

The gap between optimized and empirical value reflects multiple barriers that prevent projects from offering their full value to the bulk power system, including: limited participation in wholesale markets such as ancillary services that remain lucrative in some regions; tax-driven grid-charging restrictions for older projects; simplistic rule-based dispatch (charge in the middle of the day and discharge in the evening); imperfect price and generation forecasting; weak or missing price signals in non-ISO regions; and dispatch incentives tied to contracts or state programs rather than bulk-system value. These findings suggest that PV+S can be cost-effective from a wholesale-market perspective, but that improved market participation, forecasting, and alignment of operational incentives are needed for projects to realize their full system value proposition.