Community Solar: Major Moves in Pennsylvania, Maryland, and California

Pennsylvania

On March 26, 2024, the Community Solar Act, HB 1842, was passed by vote of the Pennsylvania General Assembly and sent for consideration by the Senate. The Act establishes a third-party-owned community solar program in the Commonwealth. Under the legislation, community solar facilities must have a maximum nameplate capacity of 20 MW (AC) for facilities located on a brownfield or rooftop and 5 MW (AC) if located elsewhere. Community solar facilities cannot have any single offtaker with a subscription for more than 50% of the facility’s capacity or energy output, except for master-metered multifamily residential or commercial buildings. At least 50% of the facility’s subscribed capacity must be for subscriptions of 25 kW or less. Some or all of the facility’s generated electricity must be credited to subscribers’ electric bills to offset all charges except volumetric or demand-based distribution charges. Community solar facilities may be remotely located and are not required to provide energy serving on-site load.

The community solar facility must be owned or operated by a “community solar organization.” Such organizations are not required to be existing electric customers, purchase electricity from a distribution company, or serve a load independent of the community solar facility. The Act specifies that community solar organizations are not considered to be public utilities solely as a result of owning or operating the facility. Renewable energy credits associated with the facility’s output are the property of the community solar organization and may be retired or transferred on behalf of subscribers.

Subscribers will receive a bill credit from the facility after the facility demonstrates: (1) an executed interconnection agreement, (2) proof of site control; (3) required permits; (4) proof that the facility will be at least 50% subscribed on the date it receives permission to operate; (5) a signed agreement for the Public Utility Commission-approved workforce development requirement; and (6) proof that the facility was or will be constructed in compliance with prevailing wage requirements. The Act precludes consolidated billing.

Excess bill credits carry over from month to month, and the electric distribution company must automatically apply excess credits to the final bill when a subscription is terminated for any reason. Subscriptions may be transferred if a subscriber relocates within the same company’s territory. Unsubscribed energy must be purchased by the electric distribution company at its wholesale energy cost, and the electric distribution company is also directed to sell this energy into the PJM market.

Community solar organizations must bill subscribers for energy efficiency charges and remit the money collected to the electric distribution company to prevent the distribution of charges to the company’s customers who do not subscribe. Organizations must also compensate the electric distribution company for reasonable costs of interconnection to the facility. Electric distribution companies may also be permitted to recover reasonable costs from each subscriber organization upon approval by the Public Utility Commission (PUC) to administer the community solar program.

The Act delegates a number of requirements to the PUC. For example, the PUC is directed to establish an appropriate bill credit that values the energy, capacity, and transmission values produced by a facility. The PUC must also establish consumer protections for residential customers and create a standardized customer disclosure form that identifies key elements of the program, subscriber rights, and costs and benefits.

The PUC must establish an interconnection working group within 90 days of the Act’s effective date if it is adopted. The working group will include electric distribution companies and other stakeholders and will submit recommendations on policies, processes, tariffs, and interconnection-related rules or standards to support transparency and efficiency. The PUC is directed to establish co-location limitations applicable to multiple community solar facilities on the same or contiguous parcels. Additionally, the PUC is permitted to adopt a mechanism to increase low-income customer participation.

California

On March 4, 2024, an administrative law judge before the California Public Utilities Commission (CPUC) issued a Proposed Decision (PD) pursuant to AB 2316, passed in 2022, which ordered the CPUC to create an affordable and equitable community solar program, and PUC Code Section 769.3. At the heart of the PD’s order were determinations regarding whether state or federal authority prevails over energy projects that connect to distribution grids, such as community solar projects. The CPUC found that community solar facilities are essentially wholesale generators and as such, must comply with the federal law known as PURPA, or the Public Utility Regulatory Policies Act of 1978. PURPA requires utilities to purchase power from “qualifying facilities” at their avoided cost, or the price that the utility would have paid someone else for that power. Pursuant to the PD, PURPA mandates that California’s community solar program follow a modified avoided cost model.

Under the proposed net value billing tariff (NVBT), which the CPUC rejected, compensation would have been based on the value of the energy delivered to the grid on an hourly basis (i.e., time-differentiated pricing). Solar industry groups proposed that this pricing model would reflect the value sum of different elements of a value stack for distributed resources, including avoided energy (using the CAISO day-ahead zonal prices), avoided capacity, and environmental values. The CPUC determined that these NVBT proposals likely conflict with federal law and state statute because they do not equate to retail rate programs but, instead, “resemble wholesale electricity procurement.”

The CPUC instead decided to adopt a new community renewable energy program that it found to be compliant with PURPA. The program will implement a capped feed-in tariff where generation resources are compensated at an avoided cost rate. Under this structure, generation resources (including community solar projects) would be required to participate in the wholesale market so that the California Independent System Operator would have visibility/dispatchability of the resources’ energy and capacity.

The revised community renewable energy program uses existing PURPA-compliant tariffs (ReMAT and PURPA Standard Offer Contracts) as a foundation onto which a subscription model is layered. Other provisions of the new community renewable energy program include the following:

• Each participating project must have a minimum of 51% of subscribers’ capacity ascribed to low-income customer subscribers;
• Low-income customers that meet each utility’s enrollment criteria will be auto-enrolled and provided an opt-out opportunity; and
• Bill credits will be provided as a flat monetary credit based on a shared percentage of resource revenue with a minimum 20% share for low-income customers.

The earliest date that the PD can be voted on April 18, 2024, during the CPUC’s next scheduled voting meeting. As of the date of this Alert, it has not yet been added to the agenda. The determination of the CPUC on the PD could potentially have significant consequences to the viability of the California community solar program.

Maryland

On March 25, 2024, the technical staff of the Maryland Public Service Commission (MPSC) filed proposed community solar regulations for review and comment, with comments due by April 22, 2024. The MPSC will hold a hearing on the proposed regulations May 15, 2024.

The proposed regulations would implement a permanent community solar program, replacing the state’s pilot program. This set of proposed regulations includes elements of the “first phase” of the program that are required to be in place by January 2025 (planning has begun for the next phase of regulation updates, primarily focused on consolidated billing, which must be adopted by 2026). Importantly, the proposed regulations, which result from over a year of working group sessions, combine into a single proposal consensus language from the working group as well as alternate language and non-consensus feedback edits. The MPSC will consider all of the proposed language (i.e., consensus and non-consensus language) during the May hearing.

Some of the key changes in the consensus language of the proposed regulations include:

• New requirements of what a community solar subscriber organization must provide to the electric company upon application, including either (a) for a system with a generating capacity of 2 MW(AC) or less, proof of application for a required permit or a preliminary step required prior to applying for a required permit or (b) for a system with a generating capacity larger than 2 MW(AC), a completeness determination issued by the MPSC or a Public Utility Law Judge in response to an application for a certificate of public convenience and necessity authorizing construction of the system.
• New co-location language that, unless an exception applies, a system may not be located on the same or an adjacent parcel of land as an existing or proposed community solar system if the total installed capacity of all systems on the same or adjacent parcel would exceed 5 MW. Some of the consensus exceptions to this requirement include projects constructed on rooftops, in industrial or brownfield sites, over parking lots or roadways, or on multilevel parking structures. Additionally, an umbrella exception applies where the combined capacity of all systems on the same or adjacent particle do not exceed 10 MW and either (a) at least 75% of the project serves LMI subscribers, or (b) systems installed under the program are used for agrivoltaics.
• A set of methods by which a subscriber organization or subscription coordinator may verify the income of a prospective subscriber for eligibility as an LMI subscriber.
• New requirements that electric companies publish certain data with the Commission annually, such as the total AC capacity of each proposed community solar project currently on the electric company’s interconnection queue.
• The addition of the term “Virtual Net Excess Generation,” or the amount of electricity generated by a community solar project and attributed to a subscriber, which would result in a negative kWh reading at the end of that subscriber’s billing cycle, if applied to the subscriber’s bill by the applicable electric company as a reduction in metered kWh.

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