by Kristina Shih

As a native Californian, I’ve been waiting years for the opportunity to become a community solar subscriber. Having worked on dozens of community solar projects in the Midwest and Northeast, I always knew there was an easier alternative to installing solar on my own home. Despite being at the forefront of renewable energy policy and development, California has yet to build a community solar market that truly benefits all consumers. But now’s the moment for the Golden State to shine with the recent passage of the new Community Renewable Energy Bill (AB 2316) in September 2022.

While Minnesota, New York, Massachusetts, and Illinois have developed robust community solar markets, California’s initial attempts fell flat with the Green Tariff Shared Renewables Program (GTSR) established by SB 43 in 2014, and the Disadvantaged Communities Green Tariff (DAC-GT) and Community Solar Green Tariff (CSGT) established by AB 327 in 2018. This mouthful of acronyms was flawed from the start, requiring utility customers to pay a premium on solar energy and making project development infeasible with narrowly defined locational requirements. After nearly 8 years, these programs have only fostered 163 MW of new community solar capacity, most of which is utility-owned and representing just 0.4% of California’s total solar capacity.[1] In contrast, New York surpassed 1 GW of community solar installed about a year ago, despite having an electricity market that is 57% the size of California’s[2].

With the passage of AB 2316, California is finally on the right path towards a more functional, market-making program. The movement to overhaul California’s flawed community solar policies took years of consensus building among a variety of stakeholders ranging from solar trade associations, ratepayer advocates, environmental justice groups and labor unions. Though it conceded it’s traditional thought-leader status to others, the California solar industry is drawing from best practices and lessons learned from other states. Developers are eager to rush into the newest community solar frontier, even though we’re not done with the policy sausage-making yet and we shouldn’t take anything for granted. Below are key issues Segue is tracking:

Rulemaking Timeline

Per AB 2316 requirements, the California Public Utilities Commission (CPUC) must first determine whether the existing community solar programs have been beneficial to ratepayers, and whether they should remain open. Between now and the end of May 2023, the CPUC will hear testimonies from the investor-owned utilities (IOUs) and various stakeholders to formally make this decision, after which a rulemaking process will commence to hash out details like program administration, project requirements, bill credit structure and crediting mechanisms, subscriber requirements and marketing practices, etc. The CPUC has until 7/1/2024 to establish the new successor community solar program.

The frontrunner proposal to define the new community solar program rules is the Net Value Billing Tariff (NVBT) sponsored by the Coalition for Community Solar Access (CCSA), a trade association for developers, financiers, and customer subscription platforms (Segue is also a member). The NVBT is broadly supported by other key stakeholders such as the Solar Energy Industry Association (SEIA), ratepayer advocates like The Utility Reform Network (TURN), environmental justice organizations and labor unions. Below are key features of the NVBT proposal:  

Source: CCSA, [3]

The IOUs prefer to keep the legacy community solar programs because they were the only entities allowed to own projects, and the NVBT proposal disrupts this paradigm with a third-party ownership model and eligible participation from community choice aggregators (CCAs). However, even if the NVBT supplants the legacy program, the IOUs will have a marketing tool to keep customers from fleeing to a CCA, while also providing grid resiliency benefits to all ratepayers. One hopes they might look to comparable circumstances in other states as justification for adopting a collaborative, optimistic tone. When community solar gardens first started in Minnesota, for example, Xcel Energy was infamously resistant. But they have since grown to embrace the program as an effective medium for customer engagement. Xcel’s program revealed deep demand amongst its ratepayer base for clean energy sources, and a third-party ownership model allowed for faster project development to meet their customer needs. While the rulemaking process remains open to rebuttal testimonies and alternative proposals from the IOUs, the broad coalition built by CCSA hopefully mitigates against the final tariff deviating substantially from the current proposal, whether the IOUs take an adversarial posture or not.  

Revenue Structure

Under the NVBT proposal, a community solar project would receive bill credits based on the energy generated for 25 years. Defined as the Export Credit Rate (ECR), the bill credit is based on the avoided cost of the exported energy to the grid, analogous to the Value of Distributed Energy Resources (VDER) rate for community solar projects in New York.

Like VDER, the ECR stack is comprised of various components which reflect when the dispatched energy is providing the greatest value to the grid. The four value components of the ECR include energy, generation capacity[4], transmission and distribution, and environmental value. While the energy component of the ECR will be floating based on the CAISO Day Ahead price[5], the non-energy components are levelized over 25 years at a fixed value using inputs from the Avoided Cost Calculator (ACC), a tool used by the CPUC to determine the benefits of distributed energy resources.

ECR Value Stack Components

Source: CCSA

The non-energy components are calculated by summing the hourly values for the Generation Capacity, Transmission and Distribution and Environmental Value inputs in the ACC, and levelized over 25 years. The resulting fixed $/kWh are then allocated to peak and off-peak hours. Under the NVBT proposal, projects would lock in the non-energy portion of the ECR based on the tariff rates at the time when the interconnection agreement is executed. CCSA is proposing that the ECR is updated by the CPUC every two years in concert with the ACC, enabling it to become an effective price signal regulating the supply of community solar+storage projects vis-à-vis California’s Integrated Resource Plan. The chart below shows ECR forecasts[6] for each of the IOUs from 2024 – 2048 by MRW and Associates, as presented on behalf of CCSA in a testimony to the CPUC in January 2023:

Source: Fulmer, Mark. Prepared Testimony on Behalf of CCSA 1/20/2023

Development Issues

As the broader community solar market has grown, so has the number of developers circling new markets nationwide and initiating land campaigns prior to final program rules. We’ve seen this story before: developers rush to grab interconnection queue positions, overwhelming the IOUs and further causing delays in the study process. Fortunately, the industry may be able to avoid the interconnection dramas played out in Illinois, Massachusetts and Maine, because the California IOUs are subject to clearly written tariffs governing a standardized distribution-level interconnection process. California utilities also have deep institutional experience with interconnecting distributed energy sources, and are mandated by the CPUC to publish unit cost guides and provide developers with the option to elect a cost certainty envelope for projects when certain upgrades are triggered. The CPUC also requires the IOUs to periodically report on interconnection timeline performance, and oversees a formal dispute resolution process for developers.  

Certain aspects about developing in California, however, will create higher-than-normal barriers to entry for less capitalized developers:


Projects up to 20 MWac will be eligible for the NVBT, but in practice developers will likely settle in the 3 5 MWac range as they seek to optimize project economics while minimizing interconnection study timelines and upgrade costs. Rule 21 has a fast-track study timeline (~ 3 months), but projects that fail to pass a series of screenings during the supplemental review will be required to undergo a system impact study and potentially a facilities study, and possibly face additional upgrade costs. Projects unable to demonstrate electrical independence from the transmission system and other earlier-queued projects will also fall out of Rule 21 into the Wholesale Distribution Access Tariff (a separate interconnection study process originally set up to provide wholesale customers seeking to delivery energy and capacity services to and from the CAISO system), potentially getting funneled into a very lengthy cluster study process.

Deposit costs during the interconnection study process can add up quickly, although projects which drop out of the queue are eligible for a full refund (less study costs incurred by the IOU). After each study milestone, the project is required to post financial security (with cash or a letter of credit) of 15% and 30% of the total cost responsibility for network upgrades, respectively. Upon GIA execution, the financial security must be modified to reflect 100% of the project’s total cost responsibility. All in all, developers will need more capital to maintain their queue positions relative to other markets (see Development Costs chart below).


While community solar projects in other states have typically been constructed on greenfield sites, development conditions are uniquely set up to enable rooftop/carport projects to contribute meaningfully towards California’s new program. On the permitting and environmental front, California has several policies that bode well for smaller-scale community solar development. SB 226 established a state-wide exemption from environmental review under the California Environmental Quality Act (CEQA) for rooftop or carport projects. Government Code Section 66105 sets limits on the amount enforcing agencies can charge for solar permitting fees, and fees can only be increased when they are explicitly justified, and the municipality determines that it has already adopted a streamlined permit approval process. Non-residential projects greater than 250 kW have their permitting fees capped at $2,400 + $5/kw above 250 kW. Of course, while developers focused on rooftop/carport sites may encounter more streamlined permitting and environmental conditions, this advantage is countered by higher likelihood of structural issues and higher engineering costs.  

Developers focusing on a greenfield play will need to navigate a slew of siting and permitting considerations given competing land uses, protected farmlands under the Williamson Act, and more rigorous environmental protections for wildlife and special status habits (riparian woodlands, vernal pools, scrublands, freshwater marshes, estuaries). While a greenfield strategy is not a non-starter, the most successful developers will be the ones who can nimbly navigate the regulatory gauntlet at minimal costs while risk-gating along the way. Examples of California-specific requirements include:

  • Environmental permitting for CEQA compliance
  • California Endangered Species Act section 2018 consultations
  • Wildlife and plant species mapping and surveys in accordance with California Department of Fish and Wildlife
  • Nesting bird surveying and monitoring for California Department of Transportation Natural Environment Study and Biological Assessment documents
  • Local requirements for pre-construction surveys, wetland and riparian restoration, mitigation monitoring
  • Multiple permitting jurisdictions/approvals required from the California Coastal Commission, California State Lands Commission, California Department of Fish and Wildlife, State Regional Water Quality Boards

Development Costs

Land costs, permitting and environmental line items will be significantly higher than other community solar markets, driving total per-project development expenditures (DevEx) substantially higher. Most importantly, the sequencing of development cost incurrence and risk mitigation is more awkward than in recent community solar market darlings like Illinois and New York. Developers will need to frontload more screening and field assessments usually deferred in states with less rigorous environmental protections. A developer in Illinois can minimize environmental spending up to the point of receiving a system impact study, but projects in California will need to incur more upfront costs to minimize the risk of uncovering issues that reveal fatal flaws, impact the overall site layout/design, or pose major cost or schedule drivers. For example, waiting too late to discover a project needs a full-blown environmental impact report could add 12 18 months to a project’s development timeline. To use a poker analogy, the “buy-ins” and ”antes” are simply bigger.

For a pipeline targeting 20 California projects (assuming 5 MWac/project), total DevEx could be as high as $10m (not including interconnection costs) versus $5m in Illinois given higher land costs, permitting costs and required site studies. “Dry hole” risk is much more meaningful given how fast environmental and permitting costs start to stack up, making it critical that developers extinguish binary risks as early as possible. While a developer in Illinois could conceivably bootstrap early-stage development for the first year, the cost curve to develop a meaningful pipeline in California requires much more capital intensity and risk tolerance, a reality which Segue is prepared to underwrite with our developer partners. 

Source: Segue Sustainable Infrastructure


The NVBT provides an elegant framework for developers to deliver economically viable and scalable projects which provide benefits to all ratepayers. The inclusion of storage enables these projects to be more responsive to the grid and improve local resiliency, and the subscriber requirements will ensure greater access by low income and disadvantaged communities to clean energy projects. Additionally, the NVBT enables building owners to comply with California’s Title 24 building code on energy efficiency. It’s been a long road to get to where we are today, but thanks to CCSA and SEIA’s hard work and commitment to coalition building, California consumers will have more choices to go solar.   

The entirety of my solar development career has trained me to expect political drama, and regulations shifting under your feet mid-way through development, but I’m optimistic that California’s new community solar + storage program is going to be as successful as the other top tier markets. California may have been late to the community solar game, but the state was busy getting far ahead of the curve with broader renewable energy procurement, and laying the groundwork to meet its ambitious net zero carbon pollution targets by 2045. Even if we’re playing the unusual part of follower in the Community Solar vertical, as goes California, so goes the nation, and I’m willing to bet on the best of the West.


Revised: 3/27/2023

[1] April 2022,


[3] As of this writing, Treasury has not released guidance confirming whether a 51% LMI subscription threshold would automatically qualify a project for the LMI tax credit adder.

[4] SEIA recommended in its commentary at the CPUC Workshop on 2/27 that the Peak Period be shifted from July – Sept to July – August in order to better align with avoided capacity costs in the ACC

[5] PG&E’s tariff would use NP-15 prices; SCE and SDG&E tariffs would use SP-15 prices

[6] Assumes 5 MWac single-axis tracking solar facility with a 5 MWac 4 hr battery (20,000 kWh) located in Fresno (PG&E, climate zone 13), San Bernardino (SCE) and San Diego (SDG&E). Battery output assumes 2.0% annual degradation, 90% round-trip efficiency and battery replacement after 15 years. Total ECR revenues steadily decrease from 2024 to 2028 due to panel and storage degradation but then sharply increase in 2039 assuming full battery replacement.