Docket Nos. ER23-2612-001, ER23-2612-002

I concur with the Commission’s order because I agree that PJM followed the cost allocation provisions in its tariff and as such Protestors’ comments were out of scope.  I also agree that Protestors have not demonstrated that PJM violated its obligations under the Operating Agreement (OA).[1]  I write separately, however, to emphasize that I take the broader concerns raised by Protestors very seriously.  I encourage PJM, its stakeholders, and the Commission to carefully examine potential changes to planning processes so as to better anticipate reliability risks and plan for them in a more proactive manner, such that a full suite of cost-effective solutions can be more carefully considered.

While Protestors fall short of demonstrating that PJM’s filing should not be accepted by the Commission, they nevertheless paint a troubling picture with regard to PJM’s grid planning.  The Grid Solutions Package that was hastily approved by PJM in response to the exigent reliability concerns identified after Brandon Shores’ deactivation notice is anticipated to cost consumers $785 million.[2]  These upgrades are being planned without the opening of a competitive proposal window, yet still will not be constructed until more than three years after the date that Talen plans to deactivate the generator.[3]  

It is hard to diagnose exactly when PJM should have started taking action on the risk of Brandon Shores retiring, but it seems that PJM contemplated the risk of retirement before the deactivation notice was sent[4] and was aware that there would be reliability concerns once the plant did retire.[5]  Could PJM have carried out planning activities sooner and in doing so identified potential solutions that more expeditiously address the reliability need, cost less, or that deliver greater value to customers?  Was there a potential for multi-value projects that would contribute to addressing this reliability need while also providing other services for PJM customers?[6]  

With the potential retirement of many more units in the region,[7] it is urgently important to understand whether any other retirements may present similar risks.  Could PJM modify its planning to ensure risks such as the one addressed today are recognized earlier and planned for in a more deliberate fashion?  Are certain potential retirements much more likely to cause reliability violations than others, and should the OA require these most challenging contingencies to be planned for in a more proactive manner, prior to any deactivation notice being given?  What helpful, concrete planning steps can be taken even in the face of uncertainty as to whether a given unit will retire?  And would it be viable to carry out a competitive proposal window where implementation of solutions was made contingent upon deactivation occurring?  I urge PJM and its stakeholders to carefully examine these questions and others that may yield insight into how best to ensure the implementation of cost-effective solutions in these circumstances.  PJM’s recent problem statement examining its deactivation notice process is a positive step addressing one piece of this broader challenge.[8]

Moreover, I wonder whether PJM’s extensive reliance on immediate need reliability solutions such as those at issue in this proceeding is in part a symptom of the failure of the region to carry out proactive, scenario-based multi-value planning.  PJM’s OA already allows for multi-driver project development,[9] which can simultaneously address reliability needs, help facilitate the achievement of state policy goals, and deliver economic benefits.  The record in response to the Commission’s regional transmission planning proposal suggests that while some local and reliability needs may persist even with greater use of proactive planning, proactive multi-value planning processes can be leveraged to replace or defer reliability projects that would otherwise be needed, at significant value to customers.[10]  Beyond considering narrower steps to improve transmission planning in response to resource retirements, I also urge PJM and its stakeholders to contemplate whether and how proactive, multi-value planning could be implemented to help address challenges such as the reliability issues caused by the Brandon Shores retirement, while also delivering other significant services to PJM customers. 

This proceeding arrives at a moment in which much legislative and regulatory attention is focused on the impact of likely impending retirements of thermal generation from PJM’s system.  While the current need may be more acute, the region has always solved for pending retirements through the process of transmission system planning.  The region is not suddenly without tools in its toolbox to maintain system reliability while largely allowing economic and policy-driven retirements to occur efficiently.  Improving the planning processes discussed above to meet the moment is likely to drive significant cost and reliability benefits for customers.

For these reasons, I respectfully concur.


[1] Order at P 24.

[2] PJM Answer at 22.

[3] Id.

[4] PJM, Energy Transition in PJM: Resource Retirements, Replacements & Risks at 8 (Feb. 24, 2023) (4R Report),

[6] The PJM OA enables multi-value projects through its “Multi-Driver Project” framework.  Under the OA, multi-driver projects are defined as “a transmission enhancement or expansion that addresses more than one of the following: reliability violations, economic constraints or State Agreement Approach initiatives.”  PJM, Intra-PJM Tariffs, OA, Definitions M – N at 5.

[7] PJM argues that 10 GW of generation is at immediate risk of retirement based on economic factors, and more than 24 GW of generation at risk of retirement based on policy considerations by 2030.  4R Report at 7-10. 

[8] See PJM, Problem/Opportunity Statement, Enhancements to Deactivation Rules (2023),

[9] PJM, Intra-PJM Tariffs, OA, Schedule 6 § 1.5.10.

[10] For example, the Midcontinent Independent System Operator submitted comments indicating that its planned LRTP Tranche 1 portfolio will bring between $23.2 billion and $52.2 billion of expected benefits to the region, including significant benefits associated with deferred or avoided infrastructure.  Comments of the Midcontinent Independent System Operator, Docket No. RM21-17, at 7-9 (Aug. 17, 2022).  The Commission’s Notice of Proposed Rulemaking expresses concern that “the absence of sufficiently long-term, comprehensive transmission planning processes appears to be resulting in piecemeal transmission expansion to address relatively near-term transmission needs” which “may result in transmission customers paying more than necessary to meet their transmission needs, customers forgoing benefits that outweigh their costs, or some combination thereof.”  Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, 179 FERC ¶ 61,028 26504 at P 25 (2022).  It also notes that “in some cases, transmission facilities selected in a regional transmission plan for purposes of cost allocation to address transmission needs driven by changes in the resource mix and demand may provide near-term reliability or economic benefits and thus potentially displace regional transmission facilities that are under consideration as part of existing regional transmission planning processes.”  Id. at P 253.  See also Pfeifenberger et al., Transmission planning for the 21st Century: Proven Practices that Increase Value and Reduce Costs, at 1-13 (Oct. 2021), available at (arguing that, as compared to proactive, multi-value transmission planning, piecemeal transmission planning via mechanisms such as individual efforts to solve near-term reliability challenges “result[s] in inefficient investments that increase total system-wide cost”). 

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