The Lawrence Berkeley National Laboratory (LBNL) has identified 2021 as a decisive turning point for hybrid renewable energy projects in the United States, particularly those pairing photovoltaic generation with battery storage. According to the Department of Energy–backed report, 67 of the 74 hybrid projects commissioned during the year were PV-plus-storage configurations. By year’s end, operational PV-hybrid capacity reached 2.2 GW, surpassing the 1.8 GW of standalone storage. In energy terms, these PV hybrids accounted for 7 GWh of storage, compared to 3.5 GWh for standalone systems.
The scale of development activity was striking. Across the country, 298 hybrid projects were in operation by the close of 2021, representing 35.9 GW of generating capacity and 3.2 GW/8.1 GWh of integrated storage. Nearly half of these were solar paired with batteries, while the remainder combined wind, fossil-fuel generation, nuclear, or other resources in various configurations. The year’s 74 new hybrid projects marked a 32% increase in count and a 21% increase in capacity over 2020, totaling 6.1 GW. Many were retrofit efforts, adding batteries to existing plants, particularly in California and Florida.
The report attributes this momentum to two converging forces: the steady decline in battery costs and the rapid expansion of variable renewable generation. These trends are reshaping grid planning and project economics, making co-located systems increasingly attractive. By the end of 2021, interconnection queues across the U.S. contained 285 GW of hybrid solar and 19 GW of hybrid wind proposals. Notably, there were 70% more hybrid plants in the queues compared to the previous year. More than 35 GW of the queued solar-plus-storage projects had already secured executed interconnection agreements, a critical milestone signaling advanced development readiness.
Regional patterns underscore the influence of market design and policy. Within the California Independent System Operator (CAISO) territory, 95% of all solar capacity in the interconnection queue was paired with storage, as was 42% of wind capacity. This concentration is unmatched in other U.S. regions. LBNL researchers explained, “Commercial interest in California no doubt derives from the state’s energy policies, but is also driven by the pronounced daily wholesale pricing patterns induced by high solar penetrations that create arbitrage opportunities for storage that do not yet exist in the same magnitude in most other wholesale markets.”
This arbitrage potential stems from California’s pronounced midday solar generation peaks, which depress wholesale prices, followed by steep evening ramps in demand. Batteries co-located with PV can store surplus midday energy and discharge during high-price evening hours, capturing value while supporting grid stability. In engineering terms, the integration reduces curtailment, improves asset utilization, and provides ancillary services such as frequency regulation.
Price trends for PV-plus-storage power purchase agreements (PPAs) have generally moved downward over time, reflecting technology maturation and competitive procurement. However, the report notes that for PPAs where PV and storage are priced separately, “levelized storage adders” have recently increased to about $5,500 per MW-month, $45 per MWh-stored (assuming one full cycle per day), or roughly $15 per MWh-PV. Hawaii was excluded from these figures due to its unique market conditions.
From a technical perspective, hybridization offers operational flexibility that standalone assets cannot match. Co-located systems can share interconnection infrastructure, reduce permitting complexity, and enable optimized dispatch strategies. For grid operators, hybrids can smooth renewable output profiles and mitigate transmission congestion. For developers, the shared site footprint and combined revenue streams can improve project bankability.
The LBNL findings also highlight the scale of potential transformation ahead. With hundreds of gigawatts of hybrid capacity in the pipeline, the engineering, market, and policy frameworks that emerge over the next decade will determine how effectively these assets integrate into the broader energy system. The report’s data suggests that the hybrid model is moving from niche application to dominant form in certain markets, driven by both economic signals and the physical realities of renewable generation patterns.