Reading the FERC December 2025 co-location order.

In March 2024, Talen Energy sold a 960 MW data center campus adjacent to the 2.5 GW Susquehanna Nuclear Power Station to Amazon Web Services for $650 million. The structure was behind-the-meter: the data center would receive power directly from the nuclear plant, bypassing the transmission system and its associated costs.

In November 2024, when PJM filed to expand co-located load from 300 MW to 480 MW, AEP and Exelon challenged the amendment. Their argument was that the arrangement would shift up to $140 million per year in transmission costs onto PJM ratepayers who had no part of the deal. FERC voted 2-1 to reject the amended Interconnection Service Agreement. Commissioner Mark Christie said the arrangement 'could have huge ramifications for both grid reliability and consumer costs.' Chairman Willie Phillips dissented, calling the rejection 'a step backward for both electric reliability and economic development.'

The resolution took 18 months of legal work. Talen ultimately restructured the arrangement into a 17-year, $18 billion front-of-meter retail power purchase agreement for up to 1,920 MW. Talen acts as a licensed retail electricity provider; PPL Electric Utilities handles transmission delivery. The new structure bypasses FERC co-location jurisdiction entirely.

The Talen-AWS restructure became the de facto case study for every subsequent BTM deal. Counsel at every energy law firm — Latham, Gibson Dunn, Baker Botts, Pillsbury — pulled it apart for hints about what FERC would and would not accept. The December 2025 order did not spring from nowhere. It emerged from a year of industry uncertainty about which co-location structures could survive a protest.

FERC's December 18, 2025 order found PJM's existing tariff 'unjust and unreasonable' for lacking rates and terms for co-located loads. The order did not prohibit co-location. It directed PJM to file three new transmission service options by February 2026, with interim deadlines running through April and a transition period through December 2028.

The three options are: (1) a modified co-location structure with specific cost allocation requirements, (2) a network transmission service path that routes the power through the grid for a brief synthetic moment before delivering it to the co-located load, and (3) a hybrid structure that is still being negotiated with stakeholders. Each option has different cost allocation, state jurisdiction, and capacity market consequences.

The order also directed PJM to answer 11 specific questions about co-location rules, with answers due in stages through April 2026. The questions touch on cost allocation, deliverability, planning reserve margins, capacity market interactions, and the definition of 'co-located load' for accounting purposes. Each answer shapes the framework that hundreds of billions of dollars of new infrastructure will be built under.

Finally, the order established a transition deadline. Existing BTM arrangements — 46 sites across PJM, totaling roughly 56 GW — must conform to the new framework by December 2028. Interim compliance milestones fall in 2026 and 2027. Every operator with an existing co-location arrangement must now plan the transition and execute it on a regulatory calendar that is still being written.

PJM filed its three transmission service options on February 16, 2026. Protests landed on March 25 from Vistra, Constellation, and the Data Center Coalition. Each protest focuses on different aspects of the filings — cost allocation, market economic impact, and the speed of the transition — and each argues for specific changes to what PJM proposed.

The reply round closes April 17, 2026. After replies, FERC will issue an order on PJM's filings. That order will determine, for years to come, how co-location deals are structured in the PJM footprint. The outcome is not preordained. The protests are substantive and the commissioners have not telegraphed a unified position.

This is the single biggest reason the paper hearing matters for anyone structuring a BTM deal right now. A deal that is filed this week is filed into an incomplete framework. A deal that is filed in May or June will land in a framework that reflects whatever FERC orders on PJM's filings. The difference between those two framings is the difference between relitigating cost allocation for a year and shipping a deal on schedule.

For the 46 existing BTM arrangements, the transition deadline is not a grace period. It is a firm date by which every arrangement must either re-file under the new framework or restructure as a front-of-meter deal. The operators with the longest runway are the ones that have already started.

Constellation's Three Mile Island restart, structured around a 20-year PPA with Microsoft, is ahead of the transition. The NRC license amendments for the Crane Clean Energy Center are progressing (April 27, 2026 intervention deadline). The deal's financial structure was designed to survive whatever FERC orders, because Constellation's counsel modeled the downside early.

Other operators are behind. The Vistra Perry Unit 1 amendment (April 10 comment deadline) and the Vistra-Comanche Peak dialogue are still exploring their options. The 46 sites include operators without the legal resources of a Constellation or a Vistra — smaller utilities with existing co-location arrangements that may not have realized the December order applied to them until after the paper hearing began.

The implication is a strong forward-looking signal: the volume of regulatory work required to execute the transition is much larger than the market has priced in. Every affected operator needs counsel, engineering, and regulatory coordination. Most need it for the first time.

A new BTM deal today has to make a structural call that would have been unnecessary in 2023. The old answer was: design the co-location, file the ISA amendment, and navigate intervener protests. The new answer is: pick one of three FERC-ordered transmission service options, model the cost allocation outcome, and commit to a structure that can survive the transition.

We walk customers through the three options as a decision tree. Option 1, the modified co-location, is most attractive for operators who value the existing tariff familiarity and are willing to accept specific cost allocation requirements. Option 2, the network service path, works for operators who want the transmission system to briefly touch the power — and absorb the associated costs — before the delivery to the co-located load. Option 3, the hybrid, is still an open question whose attractiveness depends on what PJM and FERC negotiate into the final framework.

Each option has different state-level regulatory consequences. Option 2's retail delivery component triggers state PUC oversight in a way that Option 1 does not. Option 3's hybrid structure may or may not. The choice of option has to account for the state PUC landscape in addition to the FERC framework.

Finally, every option is conditional on NRC licensing for nuclear-coupled deals. Three Mile Island, Duane Arnold, Palisades, and Comanche Peak all have their own licensing pathways. We maintain a tracker that links FERC status and NRC status together for each major deal.

If you are responsible for an affected BTM arrangement, here is the short version of what we tell customers:

1. Confirm exposure. List every co-located arrangement your company has under the PJM order. Include sites under development, sites under construction, and sites already in service.

2. Run the 2028 countdown. For each arrangement, model the milestones between now and December 2028. If any milestone depends on a FERC ruling we have not yet received, flag it.

3. Map the option space. For each arrangement, decide which of the three transmission service options is the best fit — and which ones would require a restructure you would rather avoid.

4. Track the paper hearing reply round. PJM's April 17 reply round will shape the outcome. Subscribe to the filings so your counsel sees them the day they land.

5. Coordinate with state PUCs. Every option has different state implications. Identify the state regulators that will be involved and establish a communication channel.

6. Budget for regulatory capacity. The transition will require legal, regulatory, and engineering work at a volume most operators are not currently staffed for. Build the budget and the timeline accordingly.

7. Tie the regulatory tracker to your deal room. Any deal room that treats regulatory filings as attachments rather than first-class objects will become stale within weeks. Pick a deal room that treats the regulatory graph as a live object.

We built BTM Workflow to be that deal room. It tracks the three options, the eleven open questions, and the transition deadlines. It subscribes to every filing in the proceeding and pushes updates into the customer's workspace. It has eleven pre-mapped filing categories and a precedent search corpus that includes every co-location-adjacent FERC order from 2019 forward.