Bypassing the Transmission Bottleneck: The Data Behind California's 17.5-Gigawatt Community Solar Potential

California's investor-owned utilities and state regulators argue that meeting the state's surging electricity demand requires a massive, centralized buildout of high-voltage transmission lines and utility-scale generation, justifying more than $110 billion in planned capital spending over the next five years. Conversely, distributed energy developers and grid analysts argue that the existing low-voltage distribution network already possesses the physical capacity to absorb thousands of megawatts of local solar and battery storage, bypassing transmission bottlenecks entirely and reducing system costs for all ratepayers.[1]

The debate over how to value and deploy that local capacity has paralyzed California's community solar market since the passage of initial enabling legislation in 2022. Now, a new grid capacity analysis and a statutory mandate from the California State Legislature are forcing a structural shift in how the state integrates distributed energy.[1][2]

According to an August 2026 study conducted by grid analytics firm Kevala and commissioned by the Coalition for Community Solar Access (CCSA), front-of-meter solar and storage systems could serve approximately 17.5 gigawatts of summer peak load on the distribution substations owned by Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E).[1]

That 17.5-gigawatt figure represents 32% of the expected peak demand in the California Energy Commission's "mid-case" 2025 forecast for the 2032 season. Crucially, the Kevala analysis found that this load could be served entirely locally, without requiring power to flow backward onto the higher-voltage transmission or sub-transmission systems, which would otherwise trigger costly network upgrades.[1]

The physical mechanism relies on pairing solar arrays with battery storage directly on the distribution grid. Kevala's analysis assumes these front-of-meter batteries would fully charge from co-located solar and from the grid during off-peak periods, and that host substations would be configured to redirect any backflow to other local feeders rather than onto high-voltage lines. The batteries would then discharge locally between 4 p.m. and 9 p.m. from June through September, when California experiences its highest net power demand.[1]

Kevala's modeling identified specific interconnection headroom across the state. Across the three investor-owned utilities, existing distribution substations could comfortably support 3,112 separate 5-megawatt solar-and-storage installations, which would serve 15,560 megawatts of local load. Smaller systems below 5 megawatts could serve an additional 1,976 megawatts.[1]

Southern California Edison's network showed the greatest numeric potential. The addition of 1,657 front-of-meter 5-megawatt installations on SCE's distribution grid could serve 9,188 megawatts of non-coincident summer peak load. That single-utility capacity is equivalent to 37% of SCE's expected summer peak in 2032.[1]

The economic implications of deploying this capacity are the core of the regulatory dispute. A separate study by Aurora Energy Research modeled the impact of deploying a more conservative 5.4 gigawatts of community-scale solar and storage across California over a 20-year horizon.[1]

Aurora found that this 5.4-gigawatt buildout would reduce statewide power system costs by 0.6%, generating approximately $6.5 billion in savings. Those savings materialize by bypassing transmission constraints, displacing expensive gas-fired peaker plants during evening hours, and avoiding future distribution infrastructure upgrades.[1]

Despite these modeled benefits, California currently lacks a functional community solar program. Community solar models allow multiple subscribers—particularly renters and low-income households who cannot install rooftop panels—to share the output of a local facility and receive proportional credits on their utility bills. The U.S. Department of Energy has prioritized the model to expand clean energy access nationwide.[3][4]

A 2022 state law, AB 2316, directed the California Public Utilities Commission (CPUC) to create a workable program. However, industry advocates argue the resulting CPUC framework was financially unviable. In a proposed decision earlier this year, the CPUC limited compensation for community solar projects to wholesale avoided cost under legacy frameworks, declining to compensate developers for broader grid values like avoided transmission costs.[1]

James McGarry, CCSA's California market lead, noted that the current regulatory structure fails to account for these system-wide benefits. "State policymakers have an opportunity to close the gap between the grid value that [front-of-meter] distributed energy resources can provide and how they are currently valued in state planning and procurement frameworks," McGarry said.[1]

In response to the regulatory stalemate, the California State Legislature intervened in the final days of the 2026 session. Lawmakers passed Assembly Bill 1813, which statutorily directs the CPUC to adopt a revised valuation framework for community solar paired with battery storage.[1][2]

AB 1813 requires the CPUC to value community solar and storage using the state's Avoided Cost Calculator—the exact tool regulators already use to assess the grid value of other energy resources. By mandating that new installations integrate dedicated battery storage, the legislation ensures projects can discharge during high-demand evening hours when wholesale power costs are highest, thereby maximizing their value under the calculator.[1][2]

The bill, which also mandates that a significant portion of program capacity serve low-income customers, now awaits the signature of Governor Gavin Newsom. If signed, the CPUC will be tasked with determining the specific rules for implementation, a phase where developers warn the program could still face administrative friction.[1][2]

The push for distributed generation comes as California's major utilities prepare for unprecedented centralized infrastructure spending. PG&E and SCE have informed investors they expect to spend more than $110 billion combined over the next five years to harden their grids against wildfires and integrate clean energy at the transmission level.[1]

The data indicates the physical headroom exists on the distribution grid to offset a third of California's future peak demand. If Governor Newsom signs AB 1813, the CPUC will be forced to price that local capacity using the state's Avoided Cost Calculator, setting up a direct financial comparison between the 17.5 gigawatts of distributed potential and the $110 billion in centralized upgrades the utilities have planned.[1][2]