Distribution System Interconnection Reform

Regulatory reforms to expedite and equitably prioritize interconnection of distributed energy resources is essential for energy affordability, clean energy inclusion, and grid decarbonization.

IMPACT AREA	Affordability, climate mitigation, resilience, accountability
TOPIC	Power sector, distributed energy
REGION	State, utility, local
AFFORDABILITY PATHWAY	Utility reform
OVERSIGHT	Utility Commissions
POLICY MECHANISM	Legislation, regulation

Policy OVERVIEW

Challenge

Distributed energy resources (DERs) such as rooftop and community solar and battery storage have grown exponentially in recent years,¹ but interconnecting DERs to the electricity grid—a process which, in most cases, is controlled by utility owners of local distribution systems—has failed to keep pace with this growth due to a mix of outdated and ineffective regulation combined with a lack of impactful enforcement tools or strong performance incentives. As a result of interconnection delays, customers and communities are bearing significant, unnecessary costs, including foregone monetary benefits such as customer energy savings, net metering payments, or other compensation such as tax credits and renewable energy credits, as well as direct economic losses from canceled projects.² Interconnection delays can also result in lower space leasing and tax revenues for the community, weaker local job growth in the energy field, and diminished grid and climate benefits from DER expansion. Moreover, such delays no longer only affect the more affluent households or commercial facilities that have typically adopted DERs in the past, as moderate-to-lower income households aided by lower prices and federal and state financial assistance comprise a growing share of solar adopters.³ However, despite the positive trend toward more inclusive DER adoption, lower-income and disadvantaged communities (DACs) face additional interconnection barriers in some areas due to grid infrastructure disparities that could technically limit new distributed energy deployment.⁴ Interconnection reforms therefore should include solutions to both accelerate grid access for DERs generally while also addressing grid infrastructure disparities that could additionally limit access to DERs in DACs, thus reinforcing racial equity gaps that have plagued residential clean energy development over the last 15 years.⁵

Policy Solution

States should pass legislation directing public utility commissions to develop new, comprehensive regulatory frameworks for the purpose of equitably accelerating DER interconnection in local distribution grids.

Model Policy Features⁶

In addition to basic procedural reforms such as standardized application form and processes and docket management improvements including equitable stakeholder engagement and formalized dispute resolution, there are several basic policy building blocks for improving interconnection of DERs, including equity considerations. These include:

Accelerated overall and step-by-step time limits for interconnection are adopted and standardized, with timelines scaled to load and complexity. Generally, timelines should shift from months and years to days and weeks, depending on scale and complexity.
Regulatory enforcement is also codified, which could include imposition of fines or fees adjusted for length of excessive service delays and/or compensation penalties for economic losses, applied as project credits or by other means of offsetting losses. Another approach already in use (and included as a policy example below) is to adopt a Performance Incentive Mechanism for DER interconnection, setting a target for reducing delays and incentivizing better performance with rewards or penalties depending on progress in meeting the target.
Comprehensive grid capacity data is publicly available to enable project planning by developers, community stakeholders, and local governments (for public projects); grid data transparency is coupled with interconnection reporting on queue volumes, timelines, and costs, as well as project types, sizes, attributes, and locations.⁷
Utility commissions establish Offices of Interconnection Administration and Accountability, including an Ombudsman role for direct stakeholder access in the application process as well as dispute resolution between utilities and project applicants; Interconnection Offices should additionally be responsible for monitoring, compiling of data, and periodic reporting of utilities’ compliance with interconnection requirements and timelines.
Interconnection studies are clustered for evaluating multiple projects together, to streamline application reviews and research costs and timelines, and potentially to inform cost-sharing design for upgrades serving multiple projects.⁸
First-in-first-out interconnection queues, which could monopolize grid capacity for commercial and industrial DER projects and residential DERs in affluent communities, include a fast-track priority pathway for community-led, DAC-benefiting projects; this includes financial assistance for community stakeholders to pay for sufficient and timely technical support for expedited interconnection applications.⁹
Cost calculations for distribution grid upgrades account for the full value of DERs for grid services and other utility benefits, including load-balancing and resilience characteristics; if a DER project will be compensated directly for its energy exports, via net metering, the balance of its full value, including non-energy benefits, could be applied toward reducing upgrade costs.¹⁰
In contrast to the conventional principle of “cost-causer-pays,” where interconnection applicants are fully responsible for grid upgrade costs, upgrade costs are “socialized” through specific policy mechanisms such as including reimbursement of original upgrade costs from future interconnectors to the upgraded feeder circuit, or collecting modest fees from all interconnection applicants to create a reserve fund that can be drawn on to cover project costs for major upgrades that will enable interconnection of additional projects in the future.¹¹
In any cost-sharing design, projects benefiting DACs are exempt from any upgrade costs resulting from historic underinvestment in infrastructure linked to residential redlining or other discriminatory policies and practices, including by utilities. Instead, states should be responsible for establishing alternative funding mechanisms to subsidize or fully cover interconnection costs of DAC-benefiting DER projects.
In contrast to conventional grid development, which is typically “reactive” or “load-following,” utilities embrace “integrated distribution system planning” that includes proactive assessment and implementation of grid upgrades in anticipation of higher DER penetration, for example due to state or local GHG reduction mandates for buildings and transportation.¹² First and foremost, proactive grid planning should prioritize assessment and remediation of grid disparities potentially limiting adoption/penetration of DERs in DACs, thus laying groundwork for reducing historic and persisting racial equity gaps in clean energy access. Proactive grid planning and investment is also important for identifying and remediating reliability and resilience disparities that are likely to be amplified by accelerating impacts of climate change. These upfront grid investments can help reduce interconnection delays due to distribution grid upgrade requirements, and prioritizing such investments for DACs can help to “prime” previously neglected areas for DERs deployment at greater scale, as Congress envisioned in passing the $7 billion Solar for All program in 2022.

Potential Policy Drawbacks and Pitfalls

Tiering or flexing of interconnection queues to prioritize DAC-benefiting projects or low-income households raises concerns about the need for technical support for fast-tracked applications in under-resourced communities.
If not progressively designed, mechanisms to socialize interconnection costs could lead to rising system charges for lower-income ratepayers who cannot benefit from grid upgrades because they cannot afford to adopt DERs.
Performance incentive mechanisms (PIMs) tied to Return on Equity (ROE) may be distorted by above-market ROEs, such that PIM rewards only further inflate unreasonable utility profits or incentive effects of PIM penalties are blunted by inflated profits.¹³
There could be litigation risks if interconnection delays and costs are shifted to specific classes of projects or applicants (commercial/industrial/affluent households).

Complementary Policies

For accelerated and equitable DER deployment, interconnection reforms should be coupled with targeted programmatic investments or financing policies, including:

Equitable DER financing programs for ensuring affordability of DERs in low-income and disadvantaged communities; examples include programs focused on Residential Solar +Storage systems and Community Solar projects.
State tax policies, such as progressively structured residential clean energy tax credits, as well as state investment tax credits for community solar projects serving local residents of DACs.

Additional Information: According to a grading methodology developed by the Interstate Renewable Energy Council and Vote Solar, in 2024 only one state, New Mexico, received an A for its interconnection policies; 6 states received a B, 15 states received a C, and 30 states received a D or F. “State” grades include Washington, D.C. (B) and Puerto Rico (D).¹⁴

EXAMPLES

1. State of Illinois, Performance Incentive Mechanism (PIM) for Commonwealth Edison Company (ComEd) interconnection performance. Illinois Commerce Commission (ICC) Order 22-0067.

Details:

In 2022, ComEd filed a Petition to the Illinois Commerce Commission (ICC) for approval of seven Performance Incentive Mechanisms, including interconnection performance, pursuant to requirements of Section 16.108-18(e) of the Public Utilities Act.
Upon completion of the petition docket, The ICC ordered a “symmetrical” (equal value) reward-or-penalty mechanism for the three-year period of 2024–2027, as part of ComEd’s multi-year rate plan for the same period.
The approved incentive structure entails a reward or penalty for Days Saved beyond current mandated timelines. There is a “deadband” for insignificant variations, meaning no reward or penalty for Days Saved between 10-11.4 days. ComEd is rewarded at a maximum rate of 5 basis points of return on equity (ROE) if average Days Saved exceed 15.74. Five basis points equals .05 in its ROE percentage for allowable profits; for example, ComEd’s approved ROE for 2024 was 8.905 percent, with the potential, now, to rise to 8.955 percent under its interconnection PIM. Conversely, 5 basis points of ROE are deducted, reducing it to 8.855 percent, for performance of fewer than 6.24 Days Saved.
As of the Fall of 2025, performance data for theComEd interconnection PIM were not available or being evaluated for determination of incentive amounts. In 2024, ComEd profits equaled $1.066 billion, entailing a maximum upside or downside adjustment of approximately $95 million depending on interconnection performance.

Challenges:

As noted by an intervenor in the ICC Order (Order 22-0067), ComEd had already achieved approximately 40 Days Saved for interconnection completion on average over the previous four years, so a target of less than 16 additional Days Saved over the next rate period (2024-2027) could be considered as “backsliding” from a previously higher rate of interconnection timing improvement.

2. California Public Utilities Commission (CPUC) Resolution E-5296 (2024), approving “specifics and process” of Limited Generation Profiles (LGP), a policy to avert grid overload from DER deployments without requiring expensive grid upgrades.