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The proposed federal transmission tariff of the PJM Interconnection reregulates wholesale access in a way that was unanticipated when many new large loads were planned and is opposed by some market participants.

The transmission rate case is related to but distinct from the advance notice of proposed rulemaking of the U.S. Department of Energy directing the Federal Energy Regulatory Commission (FERC) to consider reforms to speed the integration of data centers onto the grid.

The availability of both generation and transmission in PJM caught national attention in December when a scheduled capacity auction closed 6,600 MW short of its reserve margin. The Trump Administration and PJM governors called for a backstop auction, plans for which are underway at PJM.

FERC concurrently ordered PJM to offer new types of transmission services as an alternative to the existing network integration transmission service (NITS).

The new services, called firm and non-firm contract demand service, will be based on a large load’s net withdrawals from the system. FERC intended to reduce the scope of required transmission upgrades so co-location of large loads could occur faster.

Network transmission service is the second largest category of PJM billings, up more than 7pc from 2024 to $12.4 billion in 2025. Capacity is the third largest category, up nearly fourfold over the same period to $10.3 billion. These costs are passed through to customers.

A recent sample of comments filed at FERC found significant opposition to the proposal, focusing on items like a proposed grid reliance charge, rate design, transmission services used during outages and the pace of reforms.

PJM’s independent market monitor said some of FERC’s defined transmission services cannot work given the potentially very large load additions that could request service. The order “represents a set of dramatic changes in the nature of transmission service” in PJM, not all of which are workable, the monitor said.

Constellation Energy Generation, the named intervenor in the transmission docket, said FERC did not establish these major new transmission services, the first since the 1990s, “for them to be so limited and burdensome that few would want to take them.”

PJM and its transmission owners have proposed to apply a grid reliance charge to co-located load being served by onsite generation resources as a zonal charge based on the percentage of transmission depreciation and operations and maintenance expense of a transmission owner’s annual transmission revenue requirement. That expense is currently 25.8%.

Given the significance of the grid reliance charge, Geronimo Power said it expected the charge would be tied to clearly defined benefits associated with the grid impact of a co-located load that is being served by an onsite generator.

“The PJM transmission owners have not demonstrated that their proposed grid reliance charge reflects co-located loads’ actual impact on the grid and is consistent with the cost causation principle,” Geronimo said, adding that FERC should reject the proposed charge.

“It defies belief that a customer that never takes transmission service receives benefits approximating 25.8% of the transmission owner’s transmission revenue,” retail energy and generation company Vistra said.

Old Dominion Electric Cooperative said the charge appropriately reflects the fact that co- located loads are synchronized with and rely on the transmission grid. The charge ensures that these loads pay their fair share of costs commensurate with the benefits received, including the costs associated with delivery of black start and regulation services, the coop said.

Firm, non-firm rates and outages become issues

Geronimo Power, which develops data centers, renewable power and batteries, noted that transmission owners want to use the same firm contract demand transmission service rate, which are unchanged from the current NITS rate, to establish the rate for non-firm contract demand transmission.

The PJM transmission owners offer several rationales for charging co-located load taking non-firm contract demand transmission service the same rate for a lesser service, Geronimo Power said, but none are convincing.

Vistra said “while PJM and the transmission owners focus on preventing NITS customers from cross subsidizing non-firm contract demand transmission service customers, they do not acknowledge that under their proposal, it is structurally certain that non-firm contract demand transmission service customers will cross-subsidize NITS customers.”

The independent market monitor said the system would become unmanageable if all or a significant part of the data center users wanted to use non-firm service, which would not be available on a consistent basis and would therefore be meaningless.

Other commentors pointed out that the transmission owners have proposed that the non-firm service be restricted to periods when the co-located generating facility is on outage, contrary to what was ordered by FERC.

PJM’s supporting testimony attempts to justify this restriction on operational and planning complexity grounds, said Advanced Energy United and the Solar Energy Industries Association.

These concerns do not support PJM’s proposed limitation, the two groups said. They added that the interim NITS as currently proposed also leaves unclear whether co-located loads may access on-site generation during system constraint periods.

Transmission outlook

PJM wants the new transmission services to be in place in 2029, claiming three years are needed for significant changes to core markets and operations systems. FERC also ordered PJM to create an interim NITS.

Constellation said FERC should establish a separate track to promptly approve the rates and terms for an interim NITS and make them effective no later than October 1.

Vistra said that a June 1, 2029, effective date means that co-located loads will not begin to receive service until 2030. PJM said it needs to procure capacity to serve new load through the three-year forward schedule of the capacity market.

“The capacity market schedule cannot be a reason to delay the implementation of services that are not capacity-backed,” Vistra said. “PJM should be able to implement software changes much more quickly than it has proposed here.”

Transmission availability will continue to evolve in the interconnection.

In PJM’s regional transmission expansion plan released this month, the PJM board approved 122 new baseline projects based on 2025 data at an estimated cost of $11.8 billion. The board also approved the inclusion of 445 new network transmission projects at an estimated $959.1 million.

Baseline projects are regional upgrades driven by mandatory reliability standards. Network projects are specifically required to connect new generation or merchant projects.

The interconnection is forecasting a 10-year summer-normalized peak growth rate of 3.1%, driven primarily by data centers, electrification of buildings and vehicles and manufacturing.

Accelerated generator retirements continue, driven by unit age and environmental policies. In one scenario, retirements of coal, natural gas and oil units will total 41 GW by 2030. New resource additions are reaching commercial operation more slowly than anticipated.

Politicians are keeping the heat on PJM, focusing on how consumers can be protected from high capacity prices. Eight governors of PJM states sent a letter to the interconnection earlier this month which included a request that data centers pay the full cost of delivery infrastructure and power supply.

The Pennsylvania state senate environmental resources and energy committee is holding a hearing on April 28 on resource adequacy and barriers to entry for new power generation.