FERC’s Approval Redefines Interconnection Pathways for Distributed Resources in PJM
By Anthony Maceira
On December 4, 2025, the Federal Energy Regulatory Commission (FERC) approved PJM Interconnection’s proposal to modify how distribution-level energy resources are processed for interconnection. Beginning April 28, 2026, these requests will no longer move through PJM’s federal tariff procedures and instead will be subject to state and local frameworks. The approval was reported by Reuters through its coverage of the Commission’s decision, available here, and confirmed by FERC’s own announcements on ferc.gov.
This jurisdictional shift will materially affect developers and investors operating across the PJM footprint, which spans 13 states and the District of Columbia and remains a central hub for U.S. deployment of distributed generation, storage, and demand-side resources.
PJM submitted its proposal as part of an effort to reduce congestion in its regional interconnection queue and ensure that distribution-connected projects are evaluated under rules better aligned with the state-level jurisdiction governing distribution infrastructure. FERC determined that the approach is consistent with the Federal Power Act and approved the filing, as reflected in related materials available on PJM’s news and updates page.
The action also aligns with FERC’s ongoing 2025 focus on modernizing interconnection processes, refining regional planning obligations, and reviewing tariff structures affecting integration of new technologies — priorities reflected in its policy updates posted on ferc.gov.
Developers accustomed to PJM’s uniform tariff procedures will need to navigate differing state regulatory requirements, technical standards, and dispute-resolution processes. These variations may significantly affect project sequencing, diligence timelines, and local coordination.
Acquisitions, financings, and portfolio strategies involving distributed resources in PJM will now require granular jurisdiction-specific analysis. Key areas of divergence include:
These variables may influence investment assumptions even for identical asset classes across neighboring jurisdictions.
Distributed storage and hybrid configurations may face new technical or cost-allocation requirements under state processes. Behind-the-meter projects may experience heightened engagement obligations with local utilities, even when regional system impacts are minimal.
Distribution utilities will assume primary responsibility for processing technical screens, performing system impact evaluations, and coordinating with applicants. This will require updated internal procedures and may trigger increased scrutiny from state regulators tracking throughput, transparency, and timelines.
Utilities may also look to adjust cost-recovery mechanisms if increased volumes of interconnection requests drive material engineering or upgrade requirements.
Developers and investors should:
Utilities should:
Market participants should monitor:
Developers, utilities, lenders, and investors operating across PJM should begin modeling these impacts now, as cost structures, risk allocation, and project development timelines will change once distribution-level interconnection transitions fully to state oversight in 2026.
Image generated with AI.
