ER26-3380-000 · 2026-09-10 · PJM Interconnection, L.L.C.

Motion for Leave to Answer and Answer of PJM Interconnection, L.L.C. to Comments and Protests re the 07/31/2026 revised Open Access Transmission Tariff filing et al

UNITED STATES OF AMERICA 
BEFORE THE 
FEDERAL ENERGY REGULATORY COMMISSION 
 
) 
PJM Interconnection, L.L.C.                      ) 
Docket No. ER26-3380-000 
) 
 
MOTION FOR LEAVE TO ANSWER AND ANSWER OF  
PJM INTERCONNECTION, L.L.C. 
PJM Interconnection, L.L.C. (“PJM”), pursuant to Federal Energy Regulatory 
Commission (“Commission” or “FERC”) Rules of Practice and Procedure 212 and 213,1 
submits this Motion for Leave to Answer2 and Answer (“Answer”) to comments and 
protests filed in response to PJM’s proposal, filed July 31, 2026 (“July 31 Filing”),3 
revising its Open Access Transmission Tariff (“Tariff”) and the Reliability Assurance 
Agreement Among Load Serving Entities in the PJM Region (“RAA”)4 to establish the 
Reliability Backstop Procurement (“RBP”) in order to address resource adequacy concerns 
stemming from large loads (“RBP proposal”).  The RBP proposal is one part of a multi-
 
1 18 C.F.R. §§ 385.212, 385.213. 
2 Although Commission Rule 213(a)(2) does not generally permit answers to protests, the Commission 
permits answers for good cause shown, such as when an answer contributes to a more accurate and complete 
record or provides useful information that assists the Commission’s deliberative process.  This answer will 
aid the Commission’s decision-making process by providing responses to the various comments and protests 
filed in response to PJM’s filings in this docket.  PJM therefore asks that the Commission accept this Answer.  
See, e.g., PJM Interconnection, L.L.C., 182 FERC ¶ 61,073, at P 13 (2023) (“We accept the answers of 
J-Power [USA Development Co., Ltd.], [PJM Power Providers Group], PJM, Public Interest Entities, and the 
[Independent] Market Monitor [for PJM] because they have provided information that assisted us in our 
decision-making process.”); N.Y. State Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 158 FERC 
¶ 61,137, at P 29 (2017) (“We will accept the Companies’ and the Complainants’ answers because they have 
provided information that assisted us in our decision-making process.”), order granting in part & denying in 
part reh’g & clarification, 170 FERC ¶ 61,120, order on clarification, 171 FERC ¶ 61,114 (2020); Colonial 
Pipeline Co., 157 FERC ¶ 61,173, at P 23 (2016) (“In the instant case, the Commission will accept the 
Protestors’ Answers and Colonial [Pipeline Co.]’s Answer because they have provided information that 
assisted us in our decision-making process.”).   
3 PJM Interconnection, L.L.C., Reliability Backstop Procurement to Address Resource Adequacy Concerns 
Stemming from Large Loads of PJM Interconnection, L.L.C., Docket No. ER26-3380-000 (July 31, 2026). 
4 Capitalized terms not otherwise defined herein have the meaning as defined in the July 31 Filing, Tariff, 
RAA, Amended and Restated Operating Agreement of PJM (“Operating Agreement”), and Consolidated 
Transmission Owners Agreement (“CTOA”).

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pronged, ongoing effort by PJM to respond to the challenges stemming from the influx of 
large loads into the PJM Region,5 and also just one part of a multi-pronged implementation 
of the Statement of Principles Regarding PJM issued on January 16, 2026, by the National 
Energy Dominance Council (“NEDC”) and the 13 governors of the PJM states.6   
As discussed below, none of the protests, limited protests, comments, requests for 
clarification, or answers submitted in this matter7 undermine the fact that PJM’s RBP 
proposal is a just and reasonable and not unduly discriminatory or preferential means to 
procure capacity through a one-time backstop procurement.  This proposal addresses the 
influx of large loads while maintaining resource adequacy, reliability, and affordability in 
a manner that respects the divide between state and federal authorities and avoids 
disrupting existing commercial arrangements.8  Indeed, numerous PJM stakeholders and 
state commissions, representing a diverse range of interests, expressed general support for 
the RBP proposal.9  For the reasons set forth below and in PJM’s July 31 Filing, the RBP 
 
5 David E. Mills, PJM Board of Managers Chair, Board Decisional Letter on Critical Issue Fast Path - Large 
Load Additions, PJM Board of Managers (Jan. 16, 2026), https://www.pjm.com/-/media/DotCom/about-
pjm/who-we-are/public-disclosures/2026/20260116-pjm-board-letter-re-results-of-the-cifp-process-large-
load-additions.pdf [https://perma.cc/P57T-ZXYJ]. 
6 Statement of Principles Regarding PJM, National Energy Dominance Council, 1 (Jan. 16, 2026), 
https://www.energy.gov/documents/statement-principles-regarding-pjm 
[https://perma.cc/35HJ-W56E] 
(“NEDC/PJM Governors’ Principles”).  The PJM state governor signatories are the governors of the 13 states 
of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, 
Pennsylvania, Tennessee, Virginia, and West Virginia. 
7 See Appendix A, Protests, Limited Protests, Comments, and Requests for Clarification attached hereto.  
8 While PJM’s Answer does not address every argument raised by intervenors, silence on any argument 
should not be deemed as acceptance of the arguments raised.   
9 See, e.g., NJ BPU Comments at 7; Ohio FEA Comments at 6; OPSI Comments at 4; NRG Limited Protest 
at 2; DCC Comments at 2-3; Equinix Comments at 4; Base Power Comments at 1; PPL Limited Protest and 
Request for Clarification at 1.

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proposal should be accepted, and made effective, no later than September 29, 2026, as 
requested.10 
I. 
ANSWER 
A. 
The RBP Proposal Is a Measured and Timely Response that Received 
Support from a Diverse Set of Stakeholders and Reflects the Fruits of 
PJM’s Ongoing Efforts to Engage with Stakeholders.  
The RBP proposal was constructed with an eye toward how to best serve the needs 
of the PJM Region, while also supporting PJM’s core mission of maintaining the reliability 
of the electric power grid to keep the lights on for 67 million people across 13 states and 
the District of Columbia.  The RBP proposal addresses the “Herculean challenge”11 
presented by the recent resource adequacy shortfalls in the PJM Region, while 
simultaneously:  
• maintaining resource adequacy, reliability, and affordability;  
• respecting the divide between state and federal authorities through a 
carefully constructed cooperative federalism framework;  
• avoiding disruption to existing commercial arrangements;  
• supporting a concurrent bilateral contracting pathway; and 
• remaining consistent with the NEDC/PJM Governors’ Principles.   
Despite the complexity of the challenges and the numerous considerations that PJM was 
required to account for and balance, the RBP proposal garnered broad support from a 
diverse set of intervenors.12  In addition, even after the July 31 Filing, PJM continued to 
 
10 The RBP procurement window will open if and when a Commission order accepts PJM’s proposed RBP 
framework.  To the extent the RBP framework is accepted by September 29, 2026, and absent significant 
revisions or developments, PJM intends to open the procurement window on September 30, 2026.   
11 NOVEC Protest at 4 (The Herculean challenge is “[t]he success, then, of the RBP relies on the coordination 
of a multidimensional amalgam of state regulatory commissions, legislatures, governors, local governments, 
and utilities across thirteen states and the District of Columbia.”). 
12 See, e.g., Equinix Comments at 1-2, 18; OPSI Comments at 1-3; Ohio FEA Comments at 1-3, 6; Vistra 
Protest at 1-2; ICC Comments at 1-3; NRG Limited Protest at 1-3; SMECO Comments at 1-2; AEU 
Comments at 1-2; CPV Comments at 1-2; NJ BPU Comments at 1-3; PIOs Limited Protest at 1-3, 9; PPL

4 
actively engage with intervenors, and this Answer reflects several proposed clarifications 
and/or adjustments to the RBP proposal, which represent the fruits of PJM’s ongoing 
stakeholder engagement.  Furthermore, PJM has been providing states with additional 
guidance on how PJM and states will coordinate to implement the RBP proposal, while 
states have worked towards developing, or further developing, applicable rules to account 
for cost allocation of RBP Resources to retail load.  Together, PJM and the states are 
continuing to work in tandem towards the shared goal of ensuring the orderly, transparent, 
and timely execution of the proposed RBP. 
1. 
The RBP proposal received significant support from a diverse set of 
intervenors. 
The RBP proposal received comments of general support for the RBP proposal 
from a diverse set of stakeholders13 including, but not limited to:   
 
Limited Protest and Request for Clarification at 1; Google Comments at 1, 8; DCC Comments at 2-3; Amazon 
Comments at 2; AEP Limited Protest at 2; Dominion Partial Protest and Comments at 2. 
13 See, e.g., Equinix Comments at 1-2, 18; OPSI Comments at 1-3; Ohio FEA Comments at 1-3, 6; Vistra 
Protest at 1-2; ICC Comments at 1-3; NRG Limited Protest at 1-3; SMECO Comments at 1-2; AEU 
Comments at 1-2; CPV Comments at 1-2; NJ BPU Comments at 1-3; PIOs Limited Protest at 1-3, 9; PPL 
Limited  Protest and Request for Clarification at 1; Google Comments at 1; DCC Comments at 2-3; Amazon 
Comments at 2; AEP Limited Protest at 2; Dominion Partial Protest and Comments at 2.

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• State public utility and advocacy groups:  the Organization of PJM States, 
Inc. (“OPSI”),14 the Ohio’s Office of the Federal Energy Advocate (“Ohio 
FEA”),15 and the NJ BPU;16 
• Transmission Owners:  PPL Electric Utilities Corporation (“PPL”)17 and 
Dominion Energy Services, Inc. (“Dominion”);18 
• Suppliers of capacity, developers, and trade groups representing them:  
Advanced Energy United (“Advanced Energy United” or “AEU”),19 Solar 
 
14 OPSI Comments at 1 (The following OPSI members support OPSI’s comments in support of PJM’s July 31 
Filing:  the Delaware Public Service Commission, Public Service Commission of the District of Columbia, 
Illinois Commerce Commission (“ICC”), Indiana Utility Regulatory Commission, Kentucky Public Service 
Commission, Maryland Public Service Commission, Michigan Public Service Commission, New Jersey 
Board of Public Utilities (“NJ BPU”), North Carolina Utilities Commission, Public Utilities Commission of 
Ohio, Pennsylvania Public Utility Commission, Tennessee Public Utility Commission, and Virginia State 
Corporation Commission); see also id. (“OPSI supports the filing because the proposed revisions strengthen 
regional resource adequacy while appropriately recognizing that implementation will require complementary 
state action to ensure that RBP costs are allocated to the appropriate retail loads.”). 
15 Ohio FEA Comments at 3 (“The Ohio FEA supports the filing.”); id. at 6 (“PJM’s RBP is a timely effort 
to address reliability concerns caused by significant data center load growth in the region.  We urge the 
Commission to approve the filing to secure long-term capacity commitments from new resources to meet 
escalating demand and to mitigate any compounding effect on PJM’s energy and capacity markets or other 
ratepayers.”). 
16 NJ BPU Comments at 1 (“[T]he Board overall supports PJM’s proposal. . . . [T]he Board supports the 
Tariff revisions to add the targeted one-time procurement RBP starting in 2026 . . . .”); id. at 3 (“The Board 
supports PJM’s proposed Tariff revisions to conduct this backstop before waiting for an additional BRA to 
clear short.  The Board also supports assigning the costs of this procurement to zones in proportion to their 
expected large load additions.  This is necessary to ensure large loads can be made responsible for the costs, 
while recognizing that states have ultimate authority over retail cost allocations.”); id. at 7 (“[T]the Board 
ultimately supports PJM’s RBP proposal and the Board recommends approving it so PJM can run the central 
procurement in 2026.”). 
17 PPL Limited Protest and Request for Clarification at 1 (PPL “is generally supportive of the [RBP] Filing.”). 
18 Dominion Partial Protest and Comments at 3 (“Dominion generally supports the RBP as a one-time 
procurement to bring the PJM region to a more stable state of resource adequacy and pave the way for holistic 
market design reforms that will support the infrastructure needed to reliably serve load growth in the 
region. . . .  The PJM region must address near-term deficiencies to begin focusing on the long-term solution, 
which is why Dominion Energy supports the RBP.”). 
19 AEU Comments at 1 (“[Advanced Energy] United generally supports PJM’s July 31, 2026, filing as the 
best available solution to address the pressing challenge of rapid load growth and slow resource entry in a 
manner that avoids putting even greater cost burden on existing customers not contributing to the resource 
adequacy shortfall.”); id. at 28 (“[Advanced Energy] United accepts PJM’s proposed [RBP] as a necessary 
tool to address the extraordinary challenges facing the region.”).

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Energy Industries Association (“SEIA”),20 CPV Power Holdings, LP 
(“CPV”),21 and Base Power, Inc. (“Base Power”);22 
• Load Serving Entities (“LSE”):  NRG Companies (“NRG”);23  
• Public Interest Organizations (“PIO”): Sierra Club and Natural 
Resources Defense Council;24 and 
• Large Loads: Data Center Coalition (“DCC”),25 Google LLC 
(“Google”),26 and Equinix Inc. (“Equinix”).27 
Furthermore, a subset of the supporting intervenors—ranging from state public 
utility commissions to end-use customers—expressly urge the Commission to accept the 
 
20 SEIA Comments at 1 (“SEIA does not oppose the RBP Proposal.”); id. at 13 (“SEIA supports PJM’s effort 
to address the resource adequacy shortfall on an expedited basis and appreciates the opportunity to provide 
these comments.”). 
21 CPV Comments at 1 (“CPV supports the RBP Proposal and believes it is a critical step toward restoring 
resource adequacy in the PJM region.”). 
22 Base Power Comments at 1 (“Base [Power] supports the RBP and the overall structure of the proposed 
auction.”); id. at 3 (“Base [Power] supports PJM’s RBP proposal and appreciates PJM’s positive engagement 
with stakeholders on the peak-shaving opt-out structure.”). 
23 NRG includes the following subsidiaries of NRG Energy, Inc.:  NRG Business Marketing LLC; Aspen 
Gen Funding, LLC; Direct Energy Business, LLC; Doswell Limited Partnership; Energy Plus Holdings LLC; 
Enerwise Global Technologies, LLC d/b/a CPower; Green Mountain Energy Company; Helix Ironwood, 
LLC; Independence Energy Group LLC; LSP University Park, LLC; Midwest Generation LLC; NRG 
Curtailment Solutions, Inc.; Reliant Energy Northeast LLC; Riverside Generating Company, LLC; Stream 
Energy Pennsylvania, LLC; University Park Energy, LLC; and XOOM Energy, LLC.  NRG Limited Protest 
at 1 n.3; see also id. at 1 (“The NRG Companies are supportive of the RBP concept . . . .”); id. at 3 (“[T]he 
NRG Companies generally support PJM’s RBP proposal as a necessary ‘stop-gap solution[]’ to fill the 
reliability gap.” (second alteration in original) (footnote omitted)).       
24 PIOs Limited Protest at 10 (“PIOs generally support PJM’s Reliability Backstop Procurement 
proposal . . . . .”); id. at 1 (“PIOs urge the Commission to approve PJM’s RBP Filing with a 
modification . . . .”). 
25 DCC Comments at 2 (“Given the urgency of PJM’s resource adequacy challenge, DCC supports moving 
forward with the RBP as a limited, one-time backstop.”); id. at 8 (“DCC supports the Commission’s 
acceptance of PJM’s proposed [RBP] as a limited, one-time measure to address the immediate resource 
adequacy shortfall.”). 
26  Google Comments at 1 (“Google commends PJM for taking steps to ensure reliability, which must remain 
its first priority.”); id. at 8 (“Google recognizes that RBP may be a reasonable response to the current resource 
adequacy shortfall . . . .”). 
27 Equinix Comments at 1-2 (“Equinix supports the adoption of the RBP on the timeline proposed by PJM.  
It is an urgent and necessary mechanism which, if applied as intended as a one-time backstop, can help 
support much-needed near-term stability for both market and reliability conditions.”); id. at 4 (“Equinix 
supports PJM’s RBP approach as a one-time response to a severe resource adequacy shortfall posing a near-
term threat to reliability.  Equinix urges the Commission to accept the RBP on PJM’s proposed 
timeline . . . .”); id. at 18 (“Equinix supports the [RBP] as a one-time mechanism and urges the Commission 
to accept it so that the procurement window may open as scheduled.”).

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RBP proposal, particularly as the challenges posed by large-load growth require decisive 
action.28   
The RBP proposal is, at bottom, a balanced and a middle ground approach.  This 
fact is borne out again and again by the totality of the protests and comments filed in the 
above-captioned docket, which reflect that, on nearly every major issue, intervenors have 
filed critiques from different sides of that issue.  Perhaps the most readily apparent example 
is the intervenor responses to the proposed $555/megawatt (“MW”)-day Unforced 
Capacity (“UCAP”) cap on the maximum willingness to pay—some intervenors assert that 
the cap is too low, while others claim that it is too high.  As CPV appropriately and 
accurately states in its filed comments: 
The RBP is a necessary and timely response to [PJM’s] growing 
resource adequacy challenge . . . . The RBP Proposal combines 
feedback from the diverse group of parties that participated in the 
[Critical Issue Fast Path (“CIFP”)] to yield an overall package that 
aims to protect ratepayer interests while still providing the decisive 
action that the moment calls for.29   
 
28 NJ BPU Comments at 7 (“[T]he Board ultimately supports PJM’s RBP proposal and the Board 
recommends approving it so PJM can run the central procurement in 2026.”); Ohio FEA Comments at 6 (The 
Ohio FEA urges “the Commission to approve the filing to secure long-term capacity commitments from new 
resources to meet escalating demand and to mitigate any compounding effect on PJM’s energy and capacity 
markets or other ratepayers.”); OPSI Comments at 4 (“OPSI respectfully encourages the Commission to 
accept PJM’s proposed Tariff and RAA revisions and permit PJM to implement the RBP while continuing 
to pursue related reforms necessary to address the challenges posed by large-load growth.”); DCC Comments 
at 2-3 (DCC “urges the Commission to accept PJM’s filing.”); Equinix Comments at 4 (“Equinix urges the 
Commission to accept the RBP on PJM’s proposed timeline while making limited, discrete modifications 
and clarifications . . . .”); see also PIOs Limited Protest at 1 (“PIOs urge the Commission to approve PJM’s 
RBP Filing with a modification . . . .”); NRG Limited Protest at 2 (“[T]he NRG Companies respectfully urge 
the Commission to accept the July 31 Filing subject to the modifications proposed . . . .”). 
29 CPV Comments at 1-2; id. at 3 (“CPV respectfully urges [with one limited clarification,] the Commission 
to act by, and accept the RBP Proposal and Tariff changes subject to a compliance filing effective, 
September 29, 2026, as PJM requested.” (citing to July 31 Filing, Transmittal at 2-4)).

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2. 
PJM has continued to engage with the stakeholder community and 
is amenable to several clarifications and adjustments to the RBP 
proposal that have been proposed by intervenors.  
PJM appreciates the active engagement of its stakeholders on the RBP proposal and 
the constructive feedback from the stakeholder community.  PJM agrees with Base Power, 
as well as other intervenors, that the RBP proposal has been shaped and informed by PJM’s 
“positive and constructive engagement with stakeholders” during and following the CIFP, 
in spite of the “compressed timeline.”30   
In fact, since the July 31 Filing, PJM has continued to engage with its stakeholders 
and answer questions about the implementation of the RBP proposal.  After conducting 
three post-CIFP workshops to discuss and answer questions concerning RBP 
implementation details,31 and carefully considering comments, protests, requests for 
clarification, and answers filed in the above-captioned docket, PJM responds, in this 
Answer, to feedback from intervenors, and provides certain requested clarifications to the 
RBP proposal.  In several instances, as PJM discusses, below, PJM is amenable to discrete 
 
30 Base Power Comments at 1; see also PPL Limited Protest and Request for Clarification at 1 (“PPL Electric 
greatly appreciates the engagement of the [PJM] stakeholder community and the work of the PJM Board and 
staff in acting to address the capacity deficiencies arising from the 2027/2028 and 2028/2029 Reliability 
Pricing Model (“RPM”) Auctions[.]”); Calibrant Request for Clarification at 2 (“Calibrant [Energy] is 
appreciative of PJM’s engagement during the stakeholder process . . . .”); AEU Comments at 25 (“[Advanced 
Energy] United commends PJM’s engagement, through the Critical Issue Fast Path process and otherwise.”); 
PJMICC Comments at 2 (PJM Industrial Customer Coalition “wishes to express appreciation to PJM’s 
Board, Staff, and stakeholders for the intensive communication and collaboration over the past many months 
leading up to the RBP Proposal.”). 
31 July 31, 2026 Post CIFP Workshop – Technical Overview Agenda, PJM Interconnection, L.L.C. (July 31, 
2026), 
https://www.pjm.com/-/media/DotCom/committees-groups/cifp-rbp/2026/20260731/20260731-
agenda.pdf [https://perma.cc/2V6H-8CBZ]; August 10, 2026 Post CIFP Workshop – RBP Window 
Information and Manual Page Turn Agenda, PJM Interconnection, L.L.C. (Aug. 10, 2026), 
https://www.pjm.com/-/media/DotCom/committees-groups/cifp-rbp/2026/20260810/20260810-agenda.pdf 
[https://perma.cc/9BZY-SX66]; August 28, 2026 Post CIFP Workshop – Technical Overview Agenda, PJM 
Interconnection, L.L.C. (Aug. 28, 2026), https://www.pjm.com/-/media/DotCom/committees-groups/cifp-
rbp/2026/20260828/20260828-agenda.pdf [https://perma.cc/6BMJ-CEUB].

9 
adjustments to incorporate intervenors’ suggestions into the RBP proposal in a compliance 
filing if so ordered by the Commission.32   
That said, PJM recognizes that, to the extent any of the intervenors’ suggestions are 
adopted, they must be implemented without undermining other key aspects of a proposal 
that seeks “to balance urgency with market principles.”33  PJM is appreciative of the 
feedback and collaboration from intervenors and highlights some of PJM’s responses, in 
this Answer, to questions raised by intervenors: 
• PJM responds to requests to clarify the role of Electric Distributors in the 
RBP (Answer, Part I.B); 
• PJM responds to requests to clarify proposed Tariff, Attachment DD, 
section 18.1(d), the opt-out provisions for Electric Distributor zone/areas 
that address their capacity needs through peak shaving adjustment programs 
that are codified in state law and that also meet the requirements of Tariff, 
Attachment DD-2 (Answer, Part I.E.1);  
• PJM responds to the request to clarify the scope of contractual instruments 
that PJM deems functionally equivalent to and serving the same evidentiary 
purpose as electric and transmission service agreements (Answer, 
Part I.E.2);   
• PJM responds to the request for clarification that, for purposes of the 
Qualifying RBP Offset UCAP MW, incremental new generation or storage 
resource behind a previously registered end-use location should be 
permitted to be used to decrement the RBP procurement target; PJM is 
amendable to updating the proposed Tariff, Attachment DD, section 
18.2(b)(vi) as described below (Answer, Part I.E.2); 
• PJM responds to the request for clarification with respect to behind-the-
meter generation projects and whether such projects are eligible to provide 
 
32 The Commission has exercised its discretion to permit changes to tariff language identified by the filing 
party in an FPA section 205 proceeding “meant to clarify . . . existing tariff provisions, eliminate certain 
inconsistencies, and correct typographical and other errors” subject to a compliance filing implementing such 
revisions.  Cal. Indep. Sys. Operator Corp., 134 FERC ¶ 61,140, at P 1 (2011); id. PP 13-14, 42-43 (accepting 
changes to tariff language identified by the California Independent System Operator Corporation (“CAISO”) 
in its answer where CAISO agreed with intervenors that changes to the tariff would be consistent with 
CAISO’s intentions and CAISO indicated that it was willing to correct the error; accepting other tariff 
revisions correcting typographical and other errors). 
33 SEIA Comments at 2.

10 
capacity as demand response as either Qualifying RBP Offset UCAP or as 
RBP Resources (Answer, Part I.E.2);   
• PJM responds to requests for clarification of, and would be amenable to 
CPV’s suggested redlines to, Tariff, Attachment DD, section 18.5(f)(i)(2), 
clarifying the RBP gating-criteria provision requiring generation resources 
to provide evidence of 100% site control for each Generating Facility for a 
term of at least three years (Answer, Part I.F.5); and 
• PJM provides additional clarity concerning when collateral requirements 
need to be posted and how much would need to be posted in a given 
Delivery Year (Answer, Part I.J.2). 
B. 
The Role of Electric Distributors in the RBP Is Appropriately Tailored. 
Several intervenors requested clarifications concerning the role of Electric 
Distributors in the RBP, and a subset of those intervenors furthermore suggest that the RBP 
proposal exceeds the scope of Electric Distributors’ traditional roles, which are largely 
administrative in nature.34  PJM submits that the RBP relies on Electric Distributors to play 
an increased reporting and coordination role, but not to exceed the scope of their traditional 
roles.     
First, EKPC alleges that “PJM shifts a significant responsibility and considerable 
degree of discretion to Electric Distributors.”35  Similarly, Southern Maryland Electric 
Cooperative, Inc. (“SMECO”) claims that the role of Electric Distributors in the RBP is 
overly expansive and exceeds the language in the PJM’s Operating Agreement, section 
11.3.3(h) to provide PJM with accounting, customer tracking, load forecasting, and other 
data.36  But, by SMECO’s own account, the RBP proposal calls for Electric Distributors to 
report information and act as a go-between—roles that are fundamentally harmonious with 
the existing role that Electric Distributors have played in PJM.  More specifically, as 
 
34 See, e.g., SMECO Comments at 3-7; AEP Limited Protest at 30-32; EKPC Protest at 35-41. 
35 EKPC Protest at 36.  
36 SMECO Comments at 4-5.

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SMECO explains, the RBP proposal requires that Electric Distributors: (1) communicate 
opt-out request[s] and provide supporting materials to PJM; (2) report capacity offsets and 
provide supporting evidence to PJM; (3) report state/RERRA-determined allocation; (4) 
report information that feeds the Electric Distributor zone/area allocation of the RBP 
procurement Target and LSE daily formula; (5) provide inputs that impact LSE collateral.37 
Second, EKPC asserts that PJM’s RBP proposal improperly requires “Electric 
Distributors to effectively set allocation inputs for a Commission-jurisdictional charge. The 
allocation of these inputs impacts cost allocation and credit requirements.”38  These 
“allocation inputs” are, indeed, inputs to PJM forecasts that Electric Distributors already 
provide.  Ultimately, it is PJM, and, where applicable, PJM states39/Relevant Electric Retail 
Regulatory Authority (“RERRA”)—not the Electric Distributors supplying the underlying 
inputs—that will ultimately determine how such inputs inform cost allocation and credit 
requirements.   
Third, SMECO’s claim that PJM has called on Electric Distributors to “develop 
and provide distribution-impact studies for RBP [Distributed Energy Resources (“DER”)] 
Aggregation Resources” misconstrues the proposed Tariff language, which states that RBP 
Sell Offers from RBP Demand Resources (“DR”) and RBP DER Capacity Aggregation 
Resources (“DR/DER”) must be accompanied by applicable Electric Distributor 
requirements.40  PJM is not imposing, through the RBP proposal, requirements on Electric 
 
37 Id. 
38 EKPC Protest at 35. 
39 The PJM states are: Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North 
Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia. 
40 Proposed Tariff, Attachment DD, sections 18.5(f)(i)(12), 18.5(f)(i)(13).

12 
Distributors to develop new or additional studies or requirements.41  While Electric 
Distributors are, pursuant to the RBP proposal, expected to actively participate in the RBP 
by reporting information and serving as one conduit through which information flows, the 
role or function of Electric Distributors is not effectively changing.   
Fourth, as described in the July 31 Filing, Electric Distributors perform a reporting 
or administrative role in the RBP and, as American Electric Power Service Corporation 
(“AEP”) correctly notes, do not (to the extent that the same entity or subsidiary thereof 
does not occupy another role such as LSE) ultimately bear responsibility for RBP Charges.  
Finally, PJM directs intervenors to the August 28, 2026 Post-CIFP presentation, which 
addresses RBP implementation and execution details, including the various roles and 
responsibilities of PJM, Electric Distributors, Transmission Owners, LSEs, states, 
RERRAs, large loads, and other entities in the RBP.42   
C. 
Nothing in Intervenors’ Protests, Comments Call into Question the 
Justness and Reasonableness of PJM’s Proposal to Establish an RBP 
Procurement Target Based on the Observed PJM Region Reliability 
Requirement Shortfall.  
In July, the PJM Board of Managers (“PJM Board”) concluded that, in light of the 
deteriorating resource adequacy conditions in the PJM Region, “a voluntary subscription 
framework would not provide sufficient assurance that capacity equal to the identified 
near-term shortfall would actually be procured[,]”43 and ultimately directed PJM to file an 
 
41 SMECO Comments at 4-5. 
42 PJM Staff, Reliability Backstop Procurement Execution, PJM interconnection, L.L.C., 5-6 (Aug. 28, 2026), 
https://www.pjm.com/-/media/DotCom/committees-groups/cifp-rbp/2026/20260828/20260828-item-01---
reliability-backstop-procurement-execution---pjm-presentation.pdf 
[https://perma.cc/WX4T-UB8T] 
(“August 28, 2026 RBP Execution Presentation”). 
43 Paula Conboy, Chair, PJM Board of Managers, Board Decisional Letter on Critical Issue Fast Path – 
Reliability Backstop Procurement and Connect and Manage, PJM Interconnection, L.L.C., 1 (July 27, 2026), 
https://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-disclosures/2026/20260727-board-

13 
RBP proposal that would procure for the identified near-term shortfall of 6,831.3 MW 
(UCAP) of PJM’s Regional Transmission Organization (“RTO”) Reliability Requirement.   
Several protestors assert that, rather than procuring for the observed, near-term 
shortfall of 6,831.3 MW (UCAP), the RBP should be based on the Joint Electric 
Distribution Companies and DCC RBP proposal (“Coalition RBP Proposal”), which is 
centered on a voluntary, subscription-based procurement wherein LSEs would voluntarily 
opt in to the procurement on behalf of their large load customers rather than being allocated 
costs by PJM.44  It is worth noting, however, that DCC—an author of the Coalition RBP 
Proposal—was not among them.  In fact, DCC filed in support of and urged the 
Commission to accept PJM’s RBP proposal, while acknowledging that the RBP proposal 
filed by PJM on July 31 “is not the framework DCC proposed.”  According to DCC, 
“[g]iven the urgency of PJM’s resource adequacy challenge, DCC supports moving 
forward with the RBP as a limited, one-time backstop[,]” particularly as “the filed proposal 
incorporates several important elements of the [Coalition RBP Proposal].”45   
The Initial RBP Target of 6,831.3 MW (UCAP) represents a measured approach to 
addressing an urgent challenge that reflects careful consideration of many competing 
interests, as well as the role of the RBP as just one stop-gap measure in the context of more 
holistic, permanent solutions to the capacity market challenges that PJM faces today.  In 
accordance with the NEDC/PJM Governors’ Principles, PJM is on a path toward returning 
 
decisional-letter-on-cifp-reliability-backstop-procurement-and-connect-and-manage.pdf 
[https://perma.cc/V9Z7-83AH]. 
44 See, e.g., JCA Protest at 30-32; EKPC Protest at 8-9, NOVEC Protest at 25, NYU Institute Comments 
at 23. 
45 DCC Comments at 2.  Likewise, intervenor Exelon Corporation, an Electric Distributor and one of the 
authors of the Coalition RBP Proposal, did not file comments or protests in response to the July 31 Filing.  
PJM Interconnection, L.L.C., Motion to Intervene of Exelon Corporation, Docket No. ER26-3380-000 
(Aug. 4, 2026).

14 
to market fundamentals as soon as possible.46  In the meantime, the RBP proposal is just 
one piece of a multi-pronged response that is still in progress.  The RBP proposal is not a 
one-stop solution to all the challenges in PJM’s capacity market.   
The RBP proposal will address the immediate capacity shortfall by procuring 
supply that is capable of coming online quickly, has a high level of certainty of being built, 
and can dependably provide capacity through the 2042/2043 Delivery Year, while PJM 
simultaneously works toward “reform[ing] the capacity market to ensure long-term 
viability and prevent consumers from bearing excessive ongoing costs[.]”47  In other 
words, it will kick-start the ongoing process of working towards addressing capacity 
shortfalls.   
As Dominion’s protest and comments state, “[t]he RBP is not an answer to PJM’s 
resource adequacy problem but is a necessary stop-gap solution to stabilize the region and 
allow for a more holistic review of the markets.”48 The procurement target reflects the fact 
that the RBP is intended to be a bridge, not a permanent, long-term solution. 
1. 
Where LSEs have, in recent history, not independently procured 
sufficient capacity despite forecasted demand growth, there is good 
reason to find that a voluntary, subscription-based procurement will 
not ensure sufficient capacity to cover the shortfall. 
Support for an RBP based on a voluntary, subscription-based or opt-in model, in 
essence, supports more of the status quo, even when the status quo has not been working.  
In PJM, it has long been the case that LSEs, and/or large loads served by those LSEs, may 
voluntarily enter into bilateral arrangements with suppliers of new capacity, without 
 
46 NEDC/PJM Governors’ Principles at 1. 
47 Id. 
48 Dominion Partial Protest and Comments at 3.

15 
intervention from PJM.  This avenue for procuring capacity was open to the relevant parties 
long before the last two Base Residual Auctions (“BRA”) cleared short and, in fact, the 
ability to bilaterally contract for capacity even predates the advent of the RPM.  
Nevertheless, the fact of the matter remains, voluntary arrangements for new capacity have 
not met that demand, and such arrangements have only just begun to gain traction as the 
projected September date for the RBP nears.  Only in recent months, spurred by recent 
market conditions, along with this RBP proposal featuring a specific procurement target 
and PJM’s separate interim resource adequacy service (“IRAS”) proposal, have parties, 
including LSEs and/or the large loads they serve, begun to actively express greater interest 
in entering into agreements for meaningful amounts of new capacity that would even make 
a dent in the shortfall.49   
In fact, despite the longstanding ability of LSEs, and/or the large loads served by 
LSEs, and suppliers of capacity, to enter into voluntary arrangements for new capacity, 
PJM cleared short of the PJM Region Reliability Requirement in the 2028/2029 BRA for 
a second consecutive year.50  More specifically, the 2028/2029 BRA cleared 6,831.3 MW 
short of the RTO Reliability Requirement,51 up from the 6,516.6 MW shortfall observed 
 
49 Anna Flávia Rochas, PJM capacity market woes spur activity bilateral power deals, Reuters (Aug, 25, 
2026), https://www.reuters.com/business/energy/pjm-capacity-market-woes-spur-activity-bilateral-power-
deals--reeii-2026-08-26/; PSEG offers large load supply proposals in PJM’s bilateral contracting process, 
Utility Dive (Aug. 5, 2026), https://www.utilitydive.com/news/pseg-data-center-pjm-bilateral-contract-
reliability/827045/ [https://perma.cc/FLF3-MSLY].  Furthermore, entering into such bilateral arrangements 
may ultimately insulate parties from the recently proposed IRAS mechanism, if that mechanism is accepted 
by the Commission. 
50 July 31 Filing, Transmittal Letter at 7 (citing 2028/2029 Base Residual Auction Report, PJM 
Interconnection, L.L.C., 3 (July 14, 2026), https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-
auction-info/2028-2029/2028-2029-bra-results-report.pdf 
[https://perma.cc/A53K-TXXY] 
(“2028/2029 
BRA Report”)). 
51 2028/2029 BRA Report at 3.

16 
in the 2027/2028 BRA.52  The 2028/2029 BRA attracted less new capacity, even as the 
reliability requirement grew from 146,105 MW to 152,400 MW (UCAP). 
In January 2026, the NEDC/PJM Governors’ Principles implicitly recognized the 
need for a procurement target, as it would certainly not have been necessary to call for a 
reliability backstop auction to be held no later than September 2026 in the first place, were 
LSEs, the large loads they serve, and suppliers of new capacity already voluntarily entering 
into arrangements for capacity in quantities sufficient to address the shortfall.  Furthermore, 
although PJM originally proposed a longer bilateral contracting period prior to the 
commencement of the RBP auction, for the reasons outlined above, PJM’s instant proposal 
is cognizant of the NEDC/PJM Governors’ Principles requesting a backstop auction by no 
later than September 2026. 
Moreover, the facts do not support intervenors’ suggestions that a voluntary, 
subscription-based model would adequately cover the capacity shortfall.  Thus, the PJM 
Board reasonably concluded, based on those facts, that a voluntary, subscription-based 
framework would not procure sufficient new capacity to meet demand and, in fact, would 
be highly likely to fail to cover that shortfall.53   
In its protest, Northern Virginia Electric Cooperative, Inc. (“NOVEC”) counters 
that “even if [a voluntary, subscription-based model] procured less than the total shortfall, 
that should not be considered a failure when considered in the context of the” Coalition 
RBP Proposal.54  But accepting such a counterargument would effectively contradict the 
 
52 2027/2028 Base Residual Auction Report, PJM Interconnection, L.L.C., 3 (Dec. 17, 2025), 
https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-auction-info/2027-2028/2027-2028-bra-
report.pdf [https://perma.cc/TA3Y-95AX].  
53 July 31 Filing, Transmittal Letter at 21-22. 
54 NOVEC Protest at 25.

17 
fundamental core reliability goal of the RBP to acquire the capacity shortfall the region is 
already expected to experience due, in part, to individual, voluntary business decisions of 
contracting sellers and buyers of capacity. 
2. 
The procurement target represents a conservative approach based 
on known, measurable, and observable metrics, which PJM has 
shown to be just and reasonable. 
A number of intervenors assert that the procurement target may over procure for 
capacity or has not been fully supported.55  The Initial RBP Target is based on a known, 
measurable, and readily observable capacity shortfall that is not in dispute.  Compared to 
the recent resource adequacy forecasts projections, a 6,831.3 MW procurement target is 
conservative.  In fact, as explained in the July 31 Filing, “the primary purpose of the RBP 
Target is to determine how much UCAP MW is needed to meet the reliability requirement 
shortfall without over-procuring.”56 
 Indeed, as the Commission recently noted in a June 2026 order to show cause, 
“[w]hile we are encouraged by the implementation of [the RBP and other] processes to 
ensure resource adequacy and faster interconnection and ongoing stakeholder discussions, 
we remain concerned that these efforts may fall short in light of generator retirements and 
tightening supply conditions.”57   
First, PJM, the North American Electric Reliability Corporation (“NERC”), and 
other industry experts on the matter project that the capacity shortfall in the next 10 years 
will be on an order of magnitude of four to nine times the 6,831.3 MW shortfall.  PJM’s 
2025 Long-Term Load Forecast projects a peak load growth of 32 gigawatts (“GW”) from 
 
55 See, e.g., NYU Institute Comments at 23-25; ODEC Comments at 5. 
56 July 31 Filing, Transmittal Letter at 52. 
57 PJM Interconnection, L.L.C., 195 FERC ¶ 61,211, at P 103 (2026) (emphasis added).

18 
2024 to 2030, with all but 2 GW coming from data centers.  The summer peak is expected 
to reach 222 GW by 2036.  The PJM Board has warned that new large load demand could 
rise by about 70 GW by 2038, even as roughly 15 GW of generation has retired in the PJM 
footprint since 2022.  Similarly, NERC’s 2026 forecast predicts “high”58 capacity risk by 
2029.  In this context, the approximately 6.8 GW procurement target is absorbed many 
times over. 
Second, because the procurement target is deliberately conservative, despite 
assertions by some intervenors to the contrary, recent downward adjustments to near-term 
forecasted large load demand do not suggest that the need for new capacity has eroded to 
the point that 6,831.3 MW (UCAP) of new capacity risks overstating the target.  To the 
extent that forecasted large load demand may be adjusted down, the expected increase in 
demand over the foreseeable future still far exceeds 6,831.3 MW.  Additionally, while the 
procurement target is based on the BRA shortfall for the 2028/2029 Delivery Year, the 
RBP will procure resources with in-service dates up until the 2032/2033 Delivery Year.  
Allowing procurement of capacity beyond the initial 2028/2029 Delivery Year decreases 
the risk of over procurement.   
Third, the 6,831.3 MW shortfall is in and of itself already adjusted to reflect recent 
improvements to PJM’s forecasting methods.59  The 6,831.3 MW figure already 
incorporates forecast updates and improved vetting of requested adjustments for data 
 
58 2025 Long-Term Reliability Assessment, North American Electric Reliability Corporation, 8 (Jan. 2026), 
https://www.nerc.com/globalassets/our-work/assessments/nerc_ltra_2025.pdf 
[https://perma.cc/BSH7-
7ALZ]; id. at 12 (“An assessment area is determined as High Risk when established resource adequacy targets 
or requirements are not met or when probabilistic or deterministic energy analyses find that planned resources 
produce shortfalls resulting in unserved energy or load loss exceeding criteria for baseline resource 
adequacy.”). 
59 PJM’s Updated 20-Year Forecast Continues To See Significant Load-Term Load Growth, PJM Inside 
Lines 
(Jan. 
14, 
2026), 
https://insidelines.pjm.com/pjms-updated-20-year-forecast-continues-to-see-
significant-long-term-load-growth/ [https://perma.cc/W3UY-F9HE].

19 
centers and large loads including, for example, an updated load forecast for summer 2026 
that predicted a drop in peak electricity use attributed to large loads (-0.7%), compared to 
the PJM 2025 Long-Term Load Forecast Report.60  Nevertheless, as the Summer Peak and 
Winter Peak graphs from PJM’s 2026 Load Forecast Report makes clear, while slight 
downward adjustments from the 2025 forecast were made to reflect the updated 2026 
Summer and Winter Peak forecasts,61 PJM continues to expect significant and 
unprecedented growth, largely arising from large load demand. 
 
Fourth, the RBP proposal permits the initial 6,831.3 MW target to be further 
adjusted down to reflect additional new capacity brought on to serve new load and certain 
opt-outs.  Once additional new capacity and opt-outs are accounted for, the Final RBP 
Target will be lower than the Initial RBP Target of 6,831.3 MW.  In other words, while the 
 
60 See id. 
61 PJM Resource Adequacy Planning Department, 2026 PJM Load Forecast Report, PJM Interconnection, 
L.L.C., 9 (Jan. 14, 2026), https://www.pjm.com/-/media/DotCom/library/reports-notices/load-forecast/2026-
load-report.pdf [https://perma.cc/6BPF-LJYA].

20 
initial procurement target is a fixed, known quantity set by the recent 2028/2029 Delivery 
Year BRA results, the final procurement target provides the flexibility to reduce that initial 
shortfall through Qualifying RBP Offset UCAP MW or opt-outs.  This means that rather 
than being required to affirmatively opt in to the RBP, as would be the case under a 
voluntary, subscription-based model, PJM’s RBP proposal preserves opportunities to opt 
out.  Thus, once reductions for Qualifying RBP Offset UCAP MW and opt-outs are 
accounted for, the Final RBP Target will be lower than the Initial RBP Target of 
6,831.3 MW.   
The risk of over-procurement is therefore highly unlikely based on the facts and 
circumstances that PJM faces today, as well as the design of the proposed RBP Target.  
Furthermore, PJM proposes to procure for the known and measurable shortfall reflected in 
the 2028/2029 BRA in recognition that the value is not in dispute and that the RBP is not 
intended to be the one and only solution to the resource adequacy challenges facing the 
PJM Region today. 
3. 
The procurement target need not contain a locational requirement. 
Some protestors assert that the procurement target should include a locational 
requirement, and/or account for the needs of specific LSEs and/or large loads.62  Calls to 
develop a more granular RBP procurement target are misguided.   
As PJM’s July 31 Filing notes, requiring more granularity by including locational 
parameters or requiring subsequent, periodic adjustments to the target only risks skewing 
results.  Importantly, inclusion of a speculative locational parameter at this point would 
ignore the fact that:  
 
62 See, e.g., EKPC Protest at 31-33; JCA Protest at 28-29.

21 
PJM’s interconnection process ensures the initial deliverability of 
new capacity to the RTO.  Going forward, the PJM Regional 
Transmission Expansion Plan (“RTEP”) process annually studies 
and addresses any transmission upgrades needed to ensure the 
ongoing deliverability of capacity resources.  Load deliverability is 
also assessed as part of the RTEP process, which will identify 
transmission needs as load patterns change.63   
In short, inclusion of a speculative 15-year forward locational capacity requirement 
would simply ignore actual PJM’s system topology during the term of the RBP 
commitment.  Such an approach disregards the role of PJM’s interconnection and planning 
process, which studies deliverability of capacity resources to load throughout the PJM 
Region based on actual system locational needs.64 
Additional granularity or updates are also unnecessary in light of the role of the 
RBP as a stop-gap solution that procures for the RTO-wide shortfall while PJM 
simultaneously continues to make progress on a broader, holistic review of its capacity 
market, the RPM, to identify durable, more permanent solutions to concerns stemming 
from large load additions.65  This ongoing holistic review is in line with the NEDC/PJM 
Governors’ Principles, which urged PJM to “embark on a stakeholder process to reform 
the capacity market to ensure long-term viability and prevent consumers from bearing 
excessive ongoing costs,” with an ultimate goal of returning PJM to market 
fundamentals.66  The Initial RBP Target of 6,831.3 MW is a conservative and a rough 
 
63 July 31 Filing, Affidavit of Ms. Danielle Croop on Behalf of PJM Interconnection, L.L.C. (Attachment C) 
¶ 9 (“Croop Aff.”). 
64 Id. ¶ 9.  
65 See Powering Reliability Through Market Design: Addressing Rising Demand and Constrained Supply, 
and Stimulating Investment to Support Durable Reliability (May 9, 2026), https://www.pjm.com/-
/media/DotCom/library/reports-notices/special-reports/2026/20260506-powering-reliability-through-
market-design.pdf [https://perma.cc/3W8Z-M4TQ]. 
66 NEDC/PJM Governors’ Principles at 1; see also CIFP Reliability Backstop Procurement – PJM Proposal, 
PJM Interconnection, L.L.C., 1 (June 11, 2026), https://www.pjm.com/-/media/DotCom/committees-
groups/cifp-rbp/2026/20260611/20260611-item-04a---pjm-reliability-backstop-proposal---post-meeting-

22 
estimate; it is not intended to identify, with exacting precision, the full scope each PJM 
zone/area’s capacity needs and, indeed, as noted above, guards against over-procurement.  
The Commission has never required procurement targets, particularly where they are 
specifically designed to be conservative, to be calculated with exacting precision or 
continuously adjusted to reflect updated information.67 
D. 
RBP Offsets Should Neither Be Expanded to Include Additional Types of 
Capacity nor Revised to Account for Subsequent Reductions in Demand.  
A number of intervenors critique the proposed parameters for Qualifying RBP 
Offset UCAP MW, arguing that Qualifying RBP Offset UCAP MW should be expanded 
to permit additional capacity to be decremented from the Initial RBP Target or otherwise 
allow for adjustments.  The parameters for Qualifying RBP UCAP MW were thoroughly 
supported in the July 31 Filing.68  As noted above, the Commission has never required 
procurement targets to be calculated with exacting precision or continuously updated to be 
just and reasonable.   
 
materials.pdf [https://perma.cc/X7T7-5RPB] (“2026 PJM CIFP Proposal”) (providing background on 
stakeholder engagement). 
67 See, e.g., PJM Interconnection, L.L.C., 128 FERC ¶ 61,157, at P 77 (2009) (denying intervenor proposal 
“that [Interruptible Load for Reliability] capacity be determined prior to the third incremental auction so that 
this last auction would adjust total capacity procured such that PJM ultimately procured the targeted amount 
of capacity.”  Noting that “[t]his argument, however, does not go to the question of whether PJM’s proposal 
in this case is just and reasonable.  It is true that there may be more than one just and reasonable means of 
accommodating short lead-time resources in PJM's auctions, and in determining whether to accept PJM's 
filing, the Commission must only determine that PJM’s proposed solution is just and reasonable, not that it 
is superior to other possible solutions.  Interruptible Intervenors have not demonstrated that PJM’s proposal 
is unjust and unreasonable, and we therefore reject their request for rehearing.” (footnotes omitted)); see also 
Midcontinent Indep. Sys. Operator, Inc., 189 FERC ¶ 61,108 (2024) (accepting proposed Target MW Value, 
a projected new interconnection MW quantity enabled by the Joint Targeted Interconnection Queue Portfolio 
identified by the RTOs, which was a conservative estimation of the appropriate amount of generation to 
participate in the Joint Targeted Interconnection Queue Portfolio without risking oversubscription), order on 
reh’g, 191 FERC ¶ 61,231 (2025), appeals appending sub nom. Ark. Pub. Serv. Comm’n v. FERC, 
Nos. 25-60127, et al. (5th Cir. Mar. 17, 2025). 
68 July 31 Filing, Transmittal Letter at 35-44.

23 
1. 
PJM correctly concluded that only new capacity should be eligible 
to serve as Qualifying RBP Offset UCAP MW and decremented 
accordingly from the RBP procurement target. 
Some intervenors suggest that not decrementing existing capacity, already secured 
through existing bilateral arrangements with large loads from the RBP procurement 
target—either by treating that existing capacity as Qualifying RBP Offset UCAP MW or 
through an opt-out provision—risks “disrupting existing commercial arrangements.”69  As 
one intervenor observes, “[t]his does not account for new load that has entered into a 
bilateral [Power Purchase Agreement (“PPA”)] with an existing generation resource.”70 
First, the entire premise that not decrementing the RBP procurement target by the 
amount of capacity associated with an “existing generation resource” that has entered into 
a bilateral PPA with new load would “disrupt” existing commercial arrangements is 
specious at best.  Whether the RBP procurement target is reduced by the capacity 
represented in such bilateral PPAs has no direct bearing on the commercial arrangement 
itself.  The RBP does not abrogate, interfere with, or disrupt the agreement.   
Second, the purpose of the RBP is to procure new capacity provided by new 
generation resources and other capacity resources.  There has been insufficient new 
capacity to match the demand created by new load that has been coming online at a pace 
and quantity that has never been matched before.  As OPSI notes, this approach “helps 
ensure that bilateral offsets and RBP procurements result in a genuine increase in regional 
capacity rather than simply shifting existing commitments among procurement 
mechanisms.”71  The fact that new load has contracted with an existing generation resource 
 
69 See, e.g., Talen Request for Clarification at 4; Amazon Comments at 3. 
70 Id. at 4. 
71 OPSI Comments at 3.

24 
simply means that the existing generation resource is no longer serving existing load.  The 
shortfall thus remains—a shortfall that would not have existed without the demand created 
by large loads.  Indeed, the existing resources Amazon Energy LLC (“Amazon”) refers to 
in its comments72 were already accounted for in the supply curve for the 2028/2029 BRA, 
which factored into the 6,831.3 MW shortfall the initial RBP procurement target is looking 
to procure.  Allowing such existing generation to offset this target would simply not 
contribute to closing the shortfall. 
Thus, far from “double charging large loads for capacity,” requiring Qualifying 
RBP Offset UCAP MW to be new capacity matched with new load ensures that an already 
conservative Initial RBP Target is only decremented to account for new capacity and that 
new load does not simply protect itself from allocation of RBP Charges by purchasing 
existing capacity resources and leaving fewer available resources for residential and 
existing commercial customers. 
To be deemed new capacity that may serve as Qualifying RBP Offset UCAP MW, 
capacity must have neither previously received a commitment in the RPM nor been 
previously committed in a Fixed Resource Requirement (FRR”) plan, as of the beginning 
of the RBP, which is anticipated to occur in or around September 2026.73  Existing capacity 
that is already the subject of bilateral contracts is not new capacity, even where that 
capacity has entered into bilateral contracts with new load.   
 
72 Amazon Comments at 3. 
73 July 31 Filing, proposed Tariff, Attachment DD, section 18.2(a).

25 
2. 
A just and reasonable RBP proposal does not require PJM to 
decrement the Initial RBP Target to account for near-term 
reductions in forecasted demand.  
Several intervenors suggest that the RBP procurement target should be further 
adjusted to account for withdrawals of prospective large load during the RBP procurement 
window.  According to those intervenors, the quantity of withdrawn demand should be 
decremented from the Region-wide RBP Target.74  But even if there have been some 
withdrawals of prospective large loads—as reflected in the slight reduction in large load 
demand captured in the most recent PJM load forecast, that forecast nevertheless continues 
to predict steep, exponential load growth in demand.  Thus, a just and reasonable RBP 
proposal need not further decrement the RBP procurement target to account for specific, 
recent large load withdrawals. 
E. 
PJM Addresses Several Intervenor Requests for Clarification to the 
Proposed Opt-Outs. 
1. 
PJM is providing several clarifications to the peak shaving 
adjustment opt-out in response to requests from intervenors. 
Base Power, NJ BPU, and Advanced Energy United request clarifications 
concerning the proposed opt-out for Electric Distributor zone/areas that address their 
capacity needs through peak shaving adjustments.  PJM addresses those requests below. 
First, both NJ BPU and Base Power request clarification about timing of electing 
the opt out for qualifying peak shaving adjustment programs.75  PJM confirms that the 
submission of the full peak shaving adjustment plans would not be needed at the time of 
an election to opt out of the RBP.  Specifically, peak shaving adjustment plans for the 
2028/2029 Third Incremental Auction can be submitted as late as September 2027 in 
 
74 See, e.g., OPSI Comments at 3-4; JCA Protest at 10-12. 
75 NJ BPU Comments at 6-7; Base Power Comments at 2, 6-8.

26 
accordance with the existing rules specified in Tariff, Attachment DD-2.76  PJM will 
simply require an Electric Distributor that elects to opt out of the RBP that a peak shaving 
adjustment plan will be submitted in accordance with the requirements set forth in Tariff, 
Attachment DD-2 at the time it makes the opt-out request, which will be due within three 
weeks from the commencement of the RBP (i.e., if the RBP commences September 30, the 
requests would be due by October 21).   
Base Power also requests that PJM clarify “that the peak shaving decrement is not 
discounted and will have a 1:1 ratio; in other words, every 1 MW of peak-shaving 
identified by an Electric Distributor will result in 1 MW decremented from the Initial RBP 
Target, with no adjustments.”77  PJM also confirms that every MW of peak-shaving 
adjustment, converted into UCAP terms, to opt out of RBP will be used to offset the final 
RBP procurement target on a 1:1 ratio.  This approach also accommodates state policy in 
the course of determining the appropriate Final RBP Target.  Third, Base Power suggests 
that the proposed Tariff language, Attachment DD, section 18.1(d) should be revised to 
remove the words “up to” from the proposed language: 
The Initial RBP Target shall be further decremented, if requested by 
an Electric Distributor, by up to the associated MW quantity of load 
that participates in a peak shaving adjustment program where such 
Electric Distributor’s zone/area addresses their capacity needs 
through peak shaving adjustment programs that are codified in state 
law 
and 
that 
also 
meet 
the 
requirements 
of 
Tariff, 
Attachment DD-2.78 
 
76 Tariff, Attachment DD-2 (“Peak Shaving Adjustment plan shall be submitted to the Office of the 
Interconnection no later than 10 Business Days prior to September 30 to be effective for the next PJM load 
forecast update”). 
77 Base Power Comments at 2. 
78 July 31 Filing, proposed Tariff, Attachment DD, section 18.1(d).

27 
PJM does not believe that the “up to” language should be removed from the proposed Tariff 
provision.  The words “up to” signify that PJM may, to the extent the associated MW 
quantity of load participating in a peak shaving adjustment program does not meet the 
requirements of the opt-out, determine not to decrement the RBP procurement target by 
that quantity of MW.  It is also possible that an additional party already has a bilateral 
agreement which would offset the target, thus requiring less peak shaving adjustment to 
meet the total target.  Without the words “up to” in the proposed Tariff language, there 
could be confusion as to where to credit the additional non required reduction against the 
RBP procurement target. 
 
Lastly, Advanced Energy United raises concerns that “a load that successfully 
qualifies for the RBP opt-out [through participation in a qualifying peak shaving 
adjustment program] could nonetheless find itself subject to IRAS curtailment.”79  
Advanced Energy United raises this concern in response to the statement, in the July 31 
Filing, that “‘even if the Electric Distributor zone/area qualifies for and receives an opt-out 
from the RBP, the load in that zone/area may be subject to load reduction under the 
forthcoming proposal to implement an IRAS.’”80  To the extent that peak shaving 
adjustment interacts with IRAS, such issues are outside the scope of this proceeding and 
will be separately addressed in the IRAS proceeding in Docket No. ER26-3515-000.  
2. 
Clarification regarding evidence required to satisfy Qualifying RBP 
Offset UCAP MW requirements set forth in proposed Tariff, 
Attachment DD, section 18.2. 
Several intervenors seek clarifications regarding the evidence that may support 
Qualifying RBP Offset UCAP MW.  First, Tract Holding Company I, LLC (“Tract”) seeks 
 
79 AEU Comments at 6. 
80 Id. (quoting July 31 Filing, Transmittal Letter at 46).

28 
clarification with respect to the requirement that Qualifying RBP Offset UCAP MW be 
accompanied by an “executed electric service agreement or transmission service 
agreement.”81  According to Tract, other “functionally equivalent agreements that serve 
the same evidentiary purpose as electric and transmission service agreements” should 
satisfy the evidentiary requirements for Qualifying RBP Offset UCAP MW.82 Tract notes, 
for example, that new load customers may:  
have executed transmission security agreements, construction letters 
of authorization, or similar agreements have undertaken binding 
contractual and financial commitments functionally equivalent to 
those assumed under standard electric service or transmission 
service agreements.  In each case, the customer has demonstrated a 
genuine, non-speculative commitment to achieve commercial 
operation within a defined timeframe; the sole relevant distinction 
lies in the particular contractual instrument through which that 
commitment has been formalized.83 
PJM agrees that it is the binding nature of contractual agreements that supports a 
non-speculative commitment to achieve commercial operation within a defined timeframe, 
not the format in which the contractual instrument has been formalized.  PJM clarifies that, 
in the implementation of this proposed Tariff provision, it will also consider contractual 
instruments that PJM deems functionally equivalent to and serving the same evidentiary 
purpose as electric and transmission service agreements.   
Second, Calibrant Energy requests clarification with respect to whether behind-the-
meter generation projects are eligible to provide capacity as demand response either as 
Qualifying RBP Offset UCAP or as RBP Resources.84  For reasons discussed above and in 
 
81 July 31 Filing, proposed Tariff, Attachment DD, section 18.2(c). 
82 Tract Request for Clarification or Limited Protest at 4. 
83 Id. at 9. 
84 Calibrant Request for Clarification at 2.

29 
the July 31 Filing, decrements to the RBP procurement target based on Qualifying RBP 
Offset UCAP MW account for recent new capacity matched to new load.  Likewise, as 
previously discussed, PJM’s requirements and gating criteria for RBP Resources requires 
resources to meet stringent requirements to be eligible to receive potential rewards in the 
procurement and price certainty up to a term of 15 years.  To be clear, the eligibility 
requirements for Qualifying RBP Offset UCAP and RBP Resources are not the same.  To 
the extent that generation provides capacity meeting the qualifications set forth in either 
proposed Tariff, Attachment DD, section 18.2(c), to provide Qualifying RBP Offset UCAP 
MW, or the qualifications in proposed Tariff, Attachment DD, section 18.5, to serve as 
RBP Resources, that capacity can be said to contribute to addressing the resource adequacy 
shortfall. 
Third, Voltus requests clarification that, for purposes of the Qualifying RBP Offset 
UCAP MW, incremental capacity comprised of new generation or storage resource behind 
a previously registered end-use location should be permitted to be used to decrement the 
RBP procurement target.85  PJM agrees with Voltus that such an approach “hews closely 
to language PJM has used later in the proposed tariff while defining RBP resource 
eligibility.”86  To that end, PJM is amendable to updating the proposed Tariff, Attachment 
DD, section 18.2(b)(vi) as follows: 
(vi) Planned Demand Resource or Planned DER Capacity 
Aggregation Resources, as described in the RAA, Schedule 6 and 
Schedule 6.2, where such incremental capacity are not reliant on 
locations which previously provided capacity unless such previous 
location represents additional capacity resulting from an investment 
in new generation or new storage resources at that location. 
 
 
85 Voltus Comments at 9. 
86 Id.

30 
3. 
PJM understands that ODEC’s rates are not subject to regulation 
of the Virginia State Corporation Commission. 
Old Dominion Electric Cooperative (“ODEC”) raises concerns that, as an electric 
cooperative with member distribution cooperatives in Virginia—a state in which “electric 
cooperatives operate under a regulatory framework that includes oversight of rates and 
services by the Virginia State Corporation Commission”87—ODEC and its member 
distribution cooperatives may not qualify for the opt-out applicable to “Electric 
Distributor’s zone/area has rates that are not regulated by the states and is unable to address 
cost allocation associated with capacity procured in the backstop.”88  ODEC, in its 
comments, notes that it “believes the opt-out was intended to provide a reasonable 
safeguard for smaller utilities, including electric cooperatives and municipal utilities, that 
could face disproportionate exposure to Reliability Backstop Procurement obligations.”89   
As PJM described in the July 31 Filing, this narrow opt-out was designed to address 
a limited regulatory gap faced by cooperatives and municipal utilities whose rates are not 
regulated by the states.90  To the extent that cooperatives and municipal utilities’ rates are 
not governed by a state regulatory authority that would be responsible for addressing the 
potential reallocation of RBP Costs to either large loads or other zone/areas within the state, 
there is risk that those cooperatives and municipal utilities’ customers would be at risk of 
absorbing the costs of an “overbuy” if a particular large load fails to materialize.91  Thus, 
the proposed opt out should appropriately be limited only to those Electric Distributors that 
 
87 ODEC Comments at 7. 
88 July 31 Filing, proposed Tariff, Attachment DD, section 18.1(d). 
89 ODEC Comments at 8. 
90 July 31 Filing, Transmittal Letter at 45. 
91 Id.

31 
are not regulated by the state.  To the extent that “ODEC is the LSE for its member 
cooperatives” and “ODEC is not subject to rate regulation by state commissions,”92 ODEC 
would qualify as an Electric Distributor that is not subject to regulation by the state and 
may elect to opt out of the RBP. 
F. 
PJM’s Procurement Process Is Just and Reasonable. 
Several protests challenge aspects of PJM’s proposed procurement process under 
the RBP.  Specifically, those protests assert that the proposal to procure RBP Resources 
for a fixed term of up to 15 years is too long, the $555/MW-day (UCAP) cap on the 
maximum willingness to pay is too low, too high, or should not exist, and/or that the 
procurement, presently targeted to take place at the end of September 2026, should be 
delayed.  None of these arguments undermine the justness and reasonableness of PJM’s 
RBP proposal.  
1. 
Procuring RBP Resources for a fixed term of up to 15 years is just 
and reasonable and not unduly discriminatory or preferential.  
Some intervenors assert that the RBP proposal is unjust and unreasonable, because 
the RBP aims to obtain commitments of new RBP UCAP MW from RBP Resources for a 
fixed term of up to 15 years—starting as early as the 2028/2029 Delivery Year and ending 
with the 2042/2043 Delivery Year, with commitment terms of RBP Resources scheduled 
to commence service after the 2028/2029 Delivery Year shortened by a commensurate 
number of years and ending in the 2042/2043 Delivery Year.   
As noted in the July 31 Filing, the fixed, maximum 15-Delivery Year term is 
informed by the NEDC/PJM Governors’ Principles, which expressly sought “15-year price 
 
92 ODEC Comments at 9.

32 
certainty for new capacity resources[]”93 to provide “[r]evenue [c]ertainty to [n]ew 
[g]eneration[.]”94  Nevertheless several intervenors assert that procuring for a fixed term 
of up to 15 years is unjust and unreasonable.95  Those arguments are without merit. 
According to the Joint Consumer Advocates (“JCA”), procuring RBP Resources 
through a central procurement for a fixed 15-year term, ending in the 2042/2043 Delivery 
Year, is internally inconsistent with PJM’s assertion that Qualifying RBP Offset UCAP 
MW, which may decrement the RBP procurement target, may be supported by bilateral 
arrangements for new capacity resources for terms as short as five years.96   
The JCA’s protest draws a false equivalence, erroneously comparing the 
requirement that bilateral arrangements supporting Qualifying RBP Offset UCAP MW 
contract for a minimum of five Delivery Years, with the requirement that resources 
procured through the RBP offer commitments for RBP UCAP MW for a fixed period of 
15 Delivery Years.  Bilateral arrangements for new capacity are distinguishable from the 
RBP procurement mechanism.  Parties that enter into bilateral arrangements are neither 
similarly situated to the suppliers that voluntarily submit offers in the RBP, with 
PJMSettlement as the counterparty to such offers, nor to the LSEs and large loads that are 
ultimately allocated cost responsibility for RBP UCAP MW. 
 
93 NEDC/PJM Governors’ Principles at 1; see also Tariff, Attachment DD, section 16.4(a) (“The Reliability 
Backstop Auction shall obtain commitments of additional Generation Capacity Resources (or, as applicable, 
additional Base Load Generation Resources) for a term of up to fifteen (15) Delivery Years.”). 
94 NEDC/PJM Governors’ Principles at 1. 
95 See, e.g., JCA Protest at 14; ICC Comments at 4; AEP Limited Protest at 6, 28-30; Blue Ridge Comments 
at 3. 
96 JCA Protest at 14 (“The [proposed RBP] design defeats itself by requiring the purchase of longer-term 
resources while constraining the participation of shorter-term resources that could better align with the 
identified need. . . . [T]he proposed RBP design includes provisions that undercut the notion that fifteen years 
of payments are needed to address the shortfall.”).

33 
First, there is broad consensus among intervenors that the preferred method of 
meeting the resource adequacy shortfall is through bilateral arrangements between LSEs, 
and/or the end-use customers (i.e., the ratepayers) they serve, and suppliers of new 
capacity.97  Bilateral arrangements are privately negotiated business deals and, within the 
limits of the law, parties to such arrangements may freely negotiate the terms.  Parties 
voluntarily enter into these bilateral arrangements, to which PJM is not a signatory. 
Furthermore, the five Delivery Year minimum is a term required of bilateral arrangements 
that support Qualifying RBP Offset UCAP MW, not a minimum term required of all 
bilateral arrangements for new capacity.  Thus, the five-year minimum term requirement 
does not prohibit parties from entering into bilateral arrangements for new capacity with 
shorter terms.  Those arrangements would not, however, support Qualifying RBP Offset 
UCAP MW. 
Second, as PJM explained in its July 31 Filing, “a five-year term is not so lengthy 
as to undermine the flexibility needed for commercial contracting or to pose a significant 
barrier to eligibility for Qualifying RBP Offset UCAP MW . . . .”98  Bilateral arrangements 
remain the preferred approach to meeting the resource adequacy shortfall.  Establishing 
less stringent terms for Qualifying RBP Offset UCAP MW encourages parties to 
voluntarily enter into bilateral arrangements and, thus, decrement the RBP procurement 
target and reduce the quantity of UCAP MW that would otherwise be subject to the more 
interventionist RBP framework.  Thus, in concluding that the minimum term for bilateral 
arrangements supporting Qualifying RBP Offset UCAP MW should be five Delivery 
 
97 See, e.g., DCC Comments at 2; NJ BPU Comments at 2-3; OPSI Comments at 3; Dominion Partial Protest 
and Comments at 4. 
98 July 31 Filing, Transmittal Letter at 39-40.

34 
Years, PJM sought to ensure stability and certainty that new capacity would be developed 
through the arrangements without dampening parties’ willingness to enter into bilateral 
arrangements. 
Third, as PJM explained in its July 31 Filing, “bilateral agreements may not need 
to be longer than five years to develop new capacity.”99  For a bilateral arrangement, the 
end of a minimum five-year term does not necessarily suggest that the buyers in the 
arrangement will no longer be responsible for paying for the new capacity.  Rather, it 
suggests that, after a minimum five Delivery Year term, parties may seek to transfer or 
renegotiate the terms of its bilateral arrangements.  This, too, is a feature of the flexibility 
afforded business arrangements, which require little to no intervention from PJM. 
Fourth, procurement through the RBP, on the other hand, is a significant, one-time 
intervention in which PJMSettlement would serve as a counterparty that procures RBP 
Resources on behalf of LSEs.  In other words, under the RBP, PJM would step in and serve 
as the counterparty that procures supply on behalf of load.   
Fifth, the RBP is only necessary where independent contracting, self-supply, and 
other private arrangements have not proven sufficient to meet the shortfall.  Indeed, where 
parties are unable to procure, or decide not to procure, sufficient capacity for themselves 
by entering into bilateral arrangements, PJM is taking this one-time action by stepping in 
through the RBP.  As noted above, bilateral arrangements entered into independently by 
contracting parties is the preferred and more straightforward pathway to meeting the 
capacity shortfall. 
 
99 Id. at 40.

35 
Sixth, where bilateral arrangements have failed to attract sufficient new capacity to 
meet new demand, a procurement that offers a fixed term of up to 15 Delivery Years is one 
aspect of the RBP intended to attract new supply.  The 15-year term provides price certainty 
through the 2042/2043 Delivery Year, in keeping with the NEDC/PJM Governors’ 
Principles.100  Furthermore, as the NJ BPU observes, “a price commitment of up to 15 years 
for qualified new supply resources, will also help attract new supply resources.”101  
Similarly, the Ohio FEA notes that procuring “long-term capacity for a fixed term of up to 
15 years” will “incent new resources to address the capacity shortfall.”102  In other words, 
the 15-year term is intended to motivate supply to participate in meeting the procurement 
shortfall in a timely manner where other measures have failed.   
The JCA asserts, “it is also unduly discriminatory to require some ratepayers to pay 
for fifteen-year procurements when other ratepayers are insulated from RBP charges due 
to exemptions or bilateral/self-supply arrangements of only five years.”103  But ratepayers 
can choose.  The fact that such a choice gives rise to different results does not amount to 
evidence of undue discrimination. 
To be clear, the ratepayers at the center of this issue are large loads, which have 
pledged to build, bring, or buy their own energy supply and which, for all intents and 
purposes, will be responsible for the costs associated with procuring RBP Resources.  
These ratepayers are sophisticated parties that have, by their own terms, “consistently 
maintained that the most durable solution to PJM’s resource adequacy challenge is to 
 
100 NEDC/PJM Governors’ Principles at 1. 
101 NJ BPU Comments at 3. 
102 Ohio FEA Comments at 5. 
103 JCA Protest at 17.

36 
enable customers adding significant new demand to bring new supply with them.”104  To 
meet their capacity needs, these ratepayers may enter into bilateral arrangements, which 
are inherently more flexible, including with respect to the length of the term required to 
support Qualifying RBP Offset UCAP MW, and which can be used to decrement the 
procurement target of the zone/area in which that ratepayer is located.  On the other hand, 
these ratepayers may elect to not act and to thus allow PJM to procure on behalf of the LSE 
that serves them.  If ratepayers choose the latter, they face payments for RBP Resources 
for the fixed term of up to 15 Delivery Years.  Each choice presents different results and 
consequences.  Those differences are not evidence of undue discrimination against 
similarly situated ratepayers but rather the outcomes of decisions made by ratepayers who 
have elected to be situated differently.  
2. 
The $555/MW-day (UCAP) cap on the maximum willingness to pay 
in a pay-as-bid procurement is neither too high nor too low.  
PJM has proposed that the levelized procurement cost of all selected RBP Sell 
Offers not exceed a maximum willingness to pay of $555/MW-day UCAP, on a 
MW-weighted average basis over all Delivery Years of the RBP.105  In other words, under 
the pay-as-bid structure, some RBP Resources may be paid more, while others may be paid 
less than the proposed $555/MW-day (UCAP) cap. 
As the Commission order accepting the inputs arising from the latest Periodic 
Review recognizes, PJM is required to submit a Periodic Review of inputs to the RPM, 
including Point 1 on the Variable Resource Requirement (“VRR”) curve, which establishes 
 
104 DCC Comments at 2. 
105 July 31 Filing, proposed Tariff, Attachment DD, section 18.5(f)(ii).

37 
the price cap, at least every four years.106  For 2028/2029 Delivery Year BRA, the 
uncollared price cap, i.e., Point 1 on the VRR curve, of $555/MW-day (UCAP) was 
accepted by the Commission earlier this year pursuant to the Commission order finding 
PJM’s Periodic Review of certain variables and inputs to the RPM to be just and 
reasonable.107  Neither the Commission nor PJM’s Tariff requires that PJM continuously 
update its Periodic Review to reflect changing conditions. 
Some intervenors filed protests and comments asserting that the proposed 
$555/MW-day (UCAP) cap on the maximum willingness to pay is unjust and unreasonable 
either because the cap is too high or too low.  For example, Ohio Consumers’ Counsel 
(“OCC”) argues that $555/MW-day (UCAP) is unjust and unreasonable as it is 
“significantly higher than the clearing price in the 2028/2029 auction of $325/MW-day 
price cap, which also reflects the scarcity conditions in that auction.”108  JCA likewise 
argues that $555/MW-day (UCAP) is too high, because the “15-year price certainty reduces 
supplier risk and eases financing . . . the willingness to pay for a 15-year commitment—
and the price that resources should be willing to accept, if guaranteed for 15 years—should 
be substantially less than the corresponding amounts for a one-year commitment.”109  The 
Independent Market Monitor for PJM (“IMM”) asserts that the $555/MW-day cap is a year 
 
106 PJM Interconnection, L.L.C., 194 FERC ¶ 61,049, at P 44 (citing Tariff, Attachment DD, 
sections 5.10(a)(i)-(iii)), order addressing arguments raised on reh’g, 196 FERC ¶ 61,007 (2026). 
107 Id. PP 44-45.  
108 OCC Protest at 8.  
109 JCA Protest at 25-28; see IMM Protest at 27-28.

38 
out-of-date, and updating the cap to account for 2026 forwards would result in a lower cap 
of $473/MW-day (UCAP).110 
On the other hand, other filed protests and comments argue that the proposed 
$555/MW-day (UCAP) cap on the maximum willingness to pay is too low.  E-Cubed 
Policy Associates, L.L.C. (“E-Cubed”) protests that the proposed $555/MW-day UCAP 
volume weighted average price constraint “is not compensatory even under PJM’s 
assumptions” and as a result, “PJM will have trouble attracting capacity to offset any 
portion of the 6,831.3 MW UCAP shortfall.”111  NRG asserts that the RBP should not 
incorporate any cap at all as doing so “necessarily increases the risk that the RBP will clear 
short, because if the cap binds, PJM will not procure the full RBP target.”112  In the 
alternative, according to NRG, if the Commission is unwilling to accept an RBP with no 
cap, the Commission should accept a soft cap of $866/MW-day, which NRG’s expert 
witness, John R Morris, asserts to be “a level reflecting a more current estimate of the 
reference [Combustion Turbine’s (“CT”) Cost of New Entry (“CONE”)] and an energy 
and ancillary services offset.”113   
Notably, no entity that would ultimately be responsible for paying the RBP Charges 
(e.g., DCC, Google, and Amazon) raised concerns with the proposed level of the cap on 
the maximum willingness to pay set at $555/MW-day (UCAP). 
 
110 IMM Protest at 28 (“If forwards are 24 percent higher, EAS is higher, and point A of the VRR Curve = 
max[(1.15 x Gross CONE - 0.75 x Net E&AS) or (0.2 x Gross CONE)] is $473/MW-Day UCAP, not 
$555/MW-Day UCAP.” (citing id., Attachment A (Technical Appendix) at 1). 
111 E-Cubed Protest at 2. 
112 NRG Limited Protest at 6 (citing id., Affidavit of John R. Morris on Behalf of NRG Energy, Inc. 
(Attachment A) ¶ 10 (“Morris Aff.”)). 
113 NRG Limited Protest at 10.

39 
Moreover, the fact that some protests and comments argue that the cap is too high, 
while others claim it is too low, is not indicative of a flaw in the RBP proposal.  Rather, it 
is an outgrowth of PJM’s concerted effort to strike an appropriate balance and find a 
middle-ground that is just and reasonable and not unduly discriminatory or preferential.114  
Indeed, even intervenors purporting to simply update the revised cap to account for more 
current data propose vastly different figures—from the $473/MW-day cap proposed by the 
IMM, to the $866/MW-day cap calculated by NRG.  Somewhere around the middle sits 
the $555/MW-day cap proposed by PJM, based on PJM’s latest, Commission-approved 
Periodic Review. 
As the July 31 Filing explains, limiting the maximum willingness to pay with a 
price cap is necessary.  The RBP is not disciplined by direct buy bids that explicitly express 
willingness to pay and, as Ms. Danielle Croop attests, “it is not reasonable to assume that 
load should be obligated to pay an unlimited amount for supply.  As with other PJM 
procurement mechanisms, an upper bound helps.”115  Furthermore, as Ms. Croop attests, a 
cap in the context of a procurement in which PJM is not receiving direct buy bids strikes 
an appropriate balance between reliability needs and customer cost protections.116  
Simultaneously, while imposing a cap, the cap remains flexible, as it is based on a levelized 
MW-weighted average basis over all Delivery Years of the RBP.  Thus, under the proposal, 
some RBP Resources may be paid more, while others may be paid less.   
 
114 Furthermore, “[u]nder section 205 of the [Federal Power Act (“FPA”)], the Commission’s inquiry is 
limited to whether the rates proposed by a utility are just and reasonable, and the Commission need not 
determine whether a proposed rate schedule is more or less reasonable than alternative rate designs.”  ISO 
New Eng. Inc., 173 FERC ¶ 61,204, at P 34 (2020) (citing Cities of Bethany v. FERC, 727 F.2d 1131, 1136 
(D.C. Cir. 1984)). 
115 July 31 Filing, Croop Aff. ¶ 26. 
116 Id. ¶ 27.

40 
PJM agrees with JCA that a 15-year term creates revenue certainty for supply 
resources and can generally reduce financial and development risk and may improve 
financing opportunities through lower capital costs or more favorable financing terms.  
Thus, even if $555/MW-day (UCAP) were lower than the reference CT’s CONE and an 
energy and ancillary services offset—which, according to the results of the Periodic 
Review, it is not—the 15-year term provides valuable revenue certainty that mitigates 
concerns that costs have risen since the Periodic Review.  Indeed, it is notable that while a 
handful of suppliers argued against the proposed level of the cap for the maximum 
willingness to pay, other suppliers did not raise such concerns.117 
3. 
PJM has appropriately narrowed the types of capacity resources 
that are eligible to participate as RBP Resources. 
Several comments and protests suggest that the categories of resources that are 
eligible to serve as RBP Resources should be expanded, and/or that an asymmetry between 
applicable eligibility requirements for Qualifying RBP Offset UCAP MW and RBP 
Resources should be resolved in favor of more inclusive requirements.  The different 
requirements established for both Qualifying RBP Offset UCAP MW and RBP Resources 
were thoroughly debated during the CIFP process, are well considered and, for reasons set 
forth in the July 31 Filing,118 have been shown to be just and reasonable.   
First, Constellation Energy Generation, LLC (“Constellation”) suggests that the 
new Maximum Facility Output requirement should be removed from the requirements to 
qualify as RBP Resources set forth in proposed Tariff, Attachment DD, 
 
117 See generally CPV Comments. 
118 July 31 Filing, Transmittal Letter at 52-54.

41 
section18.5(b)(i),119 permitting generation resources “[c]omposed of new Installed 
Capacity and new Maximum Facility Output” to qualify as RBP Resources.  Constellation 
opines that the “relevant attribute from a resource adequacy perspective is the new Capacity 
Interconnection Rights.”120  To qualify as RBP Resources, the RBP proposal requires 
generation resources to be composed of new Installed Capacity—i.e., new nameplate 
capacity, new Maximum Facility Output, i.e., the addition of new MW that may be 
physically injected at a point of interconnection, and new Capacity Interconnection Rights, 
i.e., new deliverable and accredited MW.  These requirements ensure new capacity 
resources that are eligible to serve as RBP Resources meet stringent standards before 
receiving 15 years of price certainty through the RBP. 
Second, other intervenors suggest that capacity provided through Surplus 
Interconnection Service (“SIS”) should be eligible to qualify as RBP Resources.  As 
described in the July 31 Filing, PJM recognized that, unlike resources providing Qualifying 
RBP Offset UCAP MW, RBP Resources will have longer-term commitments and price 
certainty and therefore deliberately proposed comparatively more restrictive criteria for 
RBP Resources.121  Furthermore, as explained in the July 31 Filing and supported by the 
accompanying affidavit of Ms. Croop, PJM expressly walked through the reasoning behind 
excluding Surplus Interconnection Service, which do not have any independent rights on 
the PJM system, from qualifying as RBP Resources.122  Notwithstanding the foregoing, 
 
119 Constellation Limited Protest at 2. 
120 Id. at 14. 
121 July 31 Filing, Transmittal Letter at 52. 
122 Id. at 53-54 (citing id., Croop Aff. ¶ 20).

42 
PJM is actively addressing the alleged barriers to market participation of resources through 
SIS generally through the markets and implementation committee.123 
4. 
The proposed gating criteria are appropriately tailored to limit the 
RBP to new capacity resources with a high likelihood of coming 
online. 
Several protests raise concerns that the gating criteria are too stringent and will 
unnecessarily narrow the pool of potential supply that may participate in the RBP.  With 
respect to gating criteria applicable to Annual DR/DER in particular, some assert that the 
criteria are so stringent as to be prohibitive,124 while others assert that they are so lax as to 
permit speculative DR/DER to participate in the RBP.125  Others would have the gating 
criteria effectively expand the role of DR/DER in meeting the capacity shortfall.126 
First, in the July 31 Filing, PJM explained that “PJM will provide sellers the 
opportunity to cure any PJM-identified deficiencies.  Sellers will have five calendar days, 
or up to the close of the bid submission window, to cure.”127  PJM anticipates working 
hand-in-hand with capacity resources, including DR/DER to determine how deficiencies 
may be cured.   
 
123 Furthermore, to the extent that Advanced Energy United urges PJM to address barriers to SIS, this is 
outside the scope of this proceeding and PJM notes that it is currently in the middle of working on this issue 
through the appropriate stakeholder processes.  See Issue Charge: Hybrid Resources Market Model Selection, 
PJM Interconnection, L.L.C. (Sep. 9, 2026), https://www.pjm.com/-/media/DotCom/committees-
groups/committees/mic/2026/20260909/20260909-item-01-2---hybrid-resources-market-model-selection---
issue--charge---redline.pdf [https://perma.cc/RC5N-2VS5] (endorsed); Issue Charge: Hybrid Resources 
Market Model Selection, PJM Interconnection, L.L.C. (Aug. 5, 2026), https://www.pjm.com/-
/media/DotCom/committees-groups/committees/mic/2026/20260805/20260805-item-04-2---hybrid-
resources-market-model-selection---issue-charge.pdf?_sp=243e40e4-936b-413a-b202-
fb1b0b43f9c0.1788453807495 [https://perma.cc/B22R-DDFJ]; Market Implementation Committee Draft 
Minutes, PJM Interconnection, L.L.C. (Aug. 5, 2026), https://www.pjm.com/-/media/DotCom/committees-
groups/committees/mic/2026/20260909/20260909-draft-minutes---mic---852026.pdf 
[https://perma.cc/5XYH-8ZRG]. 
124 Voltus Comments at 11. 
125 FirstEnergy Comments and Protest at 21. 
126 AEU Comments at 17. 
127 July 31 Filing, Transmittal Letter at 72 (citing id., proposed Tariff, Attachment DD, section 18.5(f)(i)).

43 
Second, PJM has deliberately tailored the gating criteria applicable to generation 
resources and battery storage, and to DR/DER.  In each case, the gating criteria require that 
the respective resources provide sufficient evidence to provide PJM with assurances that 
the resources are highly likely to be fully developed and successful, as opposed to 
speculative and, in accordance with the purpose of the RBP, come online in relatively short 
order to meet the identified capacity shortfall through the 15-Delivery Year term.   
Voltus asserts that the requirements on DR/DER “will function as a fence, not a 
gate, with the result that few if any demand-side resources will actually offer, subverting 
PJM’s intention to afford demand-side developers an opportunity to secure long-term price 
certainty to enable broad and deep new investment in behind-the-meter assets.”128  More 
specifically, according to Voltus, the requirement on DR/DER to provide “‘[e]xecuted 
customer agreements or binding commitments covering the proposed RBP UCAP MW 
commitment’”129 is overly stringent, particularly as generation/storage resources are not 
required to provide evidence of final investments and commitments. 
The difference in the gating criteria for generation/storage resources and DR/DER 
is by design.  It is the outgrowth of PJM’s recognition that generation/storage resources are 
tied to physical assets.  For such resources, once there is “steel in the ground,” it becomes 
costly for such assets to exit the market early—i.e., prior to the completion of the 
15-Delivery Year term. 
By contrast, DR/DER is, by nature, contracts or agreements.  DR/DER contracts 
and agreements are not inherently tied to one dedicated asset.  In addition, there are 
 
128 Voltus Comments at 3. 
129 Voltus Comments at 11 (alteration in original) (quoting July 31 Filing, proposed Tariff, Attachment DD, 
section 18.5(f)(i)(10)).

44 
near-zero sunk costs associated with exiting the market or re-entering it, year-to-year.  In 
other words, by design, DR/DER may enter and exit the market year-to-year based on 
economic and other business decisions.  Indeed, the ability for DR/DER to easily enter and 
exit the market is one reason why, as Advanced Energy United notes, one significant role 
that DR/DER plays in the RBP proposal is to serve as a “bridge mechanism pending the 
availability of generation or storage capacity not yet in service.”130  On the other hand, in 
recognition of the fact that DR/DER is, in effect, represented by binding and executed 
contracts or agreements, the gating criteria need not, contrary to another protestor’s claim, 
provide evidence of “deployed enabling infrastructure[.]”131 
Finally, an RBP commitment for DR/DER is ultimately with the Curtailment 
Service Provider or DER Aggregator and not tied to one particular physical asset.  RBP is 
designed to not allow for replacement of RBP Resources. Only the committed RBP 
Resource is eligible for RBP payments. Requiring evidence that the DR/DER locations are 
contracted for 15 years ensures parity with generation/battery storage resources that 
participate in RBP.  The requirement ultimately provides PJM confidence that DR/DER 
serving as RBP Resources will actually be available for the term of the RBP commitment.  
In short, PJM’s proposed gating criteria are well considered, balanced, and just and 
reasonable.   
5. 
PJM is amenable to CPV’s suggested revision to the Site Control 
requirement set forth in the gating criteria provisions, proposed 
Tariff, Attachment DD, section 18.5(f)(i)(2).  
CPV submitted comments seeking clarification with respect to the gating criteria 
requiring that Generating Facilities provide evidence of 100% site control.  First, CPV 
 
130 AEU Comments at 16. 
131 FirstEnergy Comments and Protest at 21.

45 
suggests that, rather than requiring evidence of 100% site control for each Generating 
Facility “for a term of at least three years from the date of submission of the Application,” 
PJM should clarify the proposed Tariff language by instead requiring that the minimum 
three-year period start from the date of the RBP Sell Offer, i.e., the date of the seller’s 
submission of the offer.132  PJM recognizes that the term “Application,” may be ambiguous 
and cause confusion.  Therefore, PJM is amenable to CPV’s suggestion that the three-year 
site control requirement begin from the date when sellers submit their RBP Sell Offer.  As 
drafted in the proposed Tariff language, PJM intended the term Application to refer to the 
date of the RBP Sell Offer.   
Second, CPV observes that projects with active interconnection queue positions are 
already required to meet site control requirements as a prerequisite to continued 
advancement through the queue.  CPV asserts that imposing an additional site control 
requirement on projects that are already in the queue could inadvertently exclude resources 
with a high likelihood of coming to fruition from participating in the RBP “based solely on 
the discrepancies between the two sets of site control requirements.”133  
CPV’s request to clarify that the requirement to provide evidence of 100% site 
control for each Generating Facility for a term of at least three years should be applicable 
only to projects that do not already have an active queue position is reasonable.  Projects 
that are both already in the interconnection queue and that already meet the relevant 
prerequisites to proceed through the queue will have already demonstrated a high 
likelihood of actualization and success.  Thus, the existing site control showing required of 
 
132 CPV Comments at 4-5 (quoting July 31 Filing, Transmittal Letter at 73 n.189; id., proposed Tariff, 
Attachment DD, section 18.5(f)(i)(2)). 
133 Id. at 5.

46 
interconnection customers, combined with the fact that these resources are already in the 
queue, should suffice. 
In short, PJM believes CPV suggested redlines to proposed Tariff, Attachment DD, 
section 18.5(f)(i)(2) is reasonable and could easily make this clarification on compliance 
without jeopardizing the commencement of the RBP. 
6. 
PJM requests that the Commission exercise its discretion to correct 
a typographical error in proposed Tariff, Attachment DD, section 
18.5(d).  
Upon review, PJM identified a typographical error in proposed Tariff, 
Attachment DD, section 18.5(d).  As filed, the relevant proposed Tariff provision states: 
To qualify as a DER Capacity Aggregation Resource that supplies 
RBP UCAP MW eligible to be offered into the Reliability Backstop 
Procurement, a Planned DER Capacity Aggregation Resource must 
meet 
the 
requirements 
of 
Tariff, 
Attachment 
DD, 
sections 18.5(b)[.]134 
 
It was clearly not PJM’s intent to require DER Capacity Aggregation Resources to 
meet the requirements in section 18.5(b), which is the provisions for “Generation or Energy 
Storage Resources as an RBP Resource.”  Rather, PJM’s intent was to refer to the general 
requirements for all resources, in Tariff, Attachment DD, section 18.5(a), “RBP Seller 
Eligibility to Participate and General Requirements for Resources Supporting RBP UCAP 
MW.”  PJM therefore respectfully requests that the Commission exercise its discretion135 
to permit PJM, on compliance, to revise the above, proposed Tariff language to replace the 
reference to “sections 18.5(b)” with “section 18.5(a).”  
 
134 Proposed Tariff, Attachment DD, section 18.5(d). 
135 Cal. Indep. Sys. Operator Corp., 134 FERC ¶ 61,140 at P 1 (The Commission has exercised its discretion 
to permit changes to tariff language identified by the filing party in an FPA section 205 proceeding “meant 
to clarify . . . existing tariff provisions, eliminate certain inconsistencies, and correct typographical and other 
errors” subject to a compliance filing implementing such revisions.).

47 
G. 
The Requirement for RBP Resources to Offer into the RPM As 
Price-Takers Is Just and Reasonable. 
Constellation and NRG assert that PJM’s proposal to require RBP Resources to 
offer into the RPM as price-takers is unjust and unreasonable.  According to Constellation 
and NRG, offering RBP Resources into the RPM as price takers will distort RPM Auction 
clearing prices.  Both NRG and Constellation advocate for measures that would effectively 
increase RPM clearing prices. 
1. 
Constellation and NRG rely on arguments that the Commission has 
consistently rejected. 
The Commission has consistently rejected the position that requiring resources that 
are procured outside of a capacity market to offer into the capacity market as price takers 
would unjustly and unreasonably distort or suppress capacity market clearing prices.136  
Indeed, as recently as last year, Commission held that offering Reliability Must Run 
(“RMR”) resources into the RPM as price takers “is just and reasonable and consistent with 
Commission precedent[,]” because it: 
reduces the risk that load will procure excess capacity and pay for 
capacity twice as a result, once through the capacity market and 
again through an RMR agreement.  In other words, including 
qualifying RMR resources in the capacity market supply stack with 
$0/MW-day offers ensures that these resources clear the market, 
such that consumers are protected against excessive capacity 
costs.137 
The Commission expressly stated that it was “not persuaded by protestors’ concerns that 
price-taker treatment of RMR resources may result in capacity market prices that do not 
 
136 See PJM Interconnection, L.L.C., 190 FERC ¶ 61,088, at P 50 (2025) (rejecting, inter alia, Constellation’s 
arguments against offering RMR Resources into the RPM as price takers); ISO New Eng. Inc., 165 FERC 
¶ 61,202, at P 65 (2018), order addressing arguments raised on reh’g, 173 FERC ¶ 61,204 (2020); N.Y. 
Indep. Sys. Operator, Inc., 150 FERC ¶ 61,116 (2015); N.Y. Indep. Sys. Operator, Inc., 155 FERC ¶ 61,076 
(2016) (“2016 NYISO RMR Order”); N.Y. Indep. Sys. Operator, Inc., 161 FERC ¶ 61,189 (2017), order on 
reh’g, 163 FERC ¶ 61,047 (2018). 
137 PJM Interconnection, 190 FERC ¶ 61,088 at P 50.

48 
reflect system needs and result in price suppression through the displacement of cost-based 
capacity offers.”138   
The Commission has consistently found that the interest in avoiding 
double-payment outweighs the concern of potential price distortion or price suppression.139  
Intervenors’ protests, including expert testimony attached to those protests, largely mirror 
those lodged with respect to challenges to RTO/Independent System Operator (“ISO”) 
proposals to treat RMR resources that receive out-of-market payments as price takers in 
capacity markets.  In its July 31 Filing, PJM explains that requiring the portion of an RBP 
Resource that has committed RBP UCAP MW to be offered into the RPM as a price taker 
is necessary where RBP Resources are already being paid for by the responsible LSEs.  
Placing a must-offer requirement on RBP Resources and requiring such offers to be 
submitted as price takers during the term of such commitment ensures that load does not 
double pay for capacity.140   
In its protest, Constellation argues that requiring RBP Resources to offer as price-
takers will distort the RPM price signal, and may “increase[] retirement risk, incent[] 
resources to export to other markets, and delay[] market entry and capital investment—
 
138 Id. 
139 See, e.g., PJM Interconnection, L.L.C., 137 FERC ¶ 61,145, at P 208 (2011) (accepting PJM’s proposed 
approach to self-supply resources in capacity auction finding that “it appropriately balances the need to 
protect against uneconomic entry while also mitigating parties’ concerns about having to pay twice for 
capacity as a result of failing to clear in RPM.”);  ISO New Eng. Inc., 173 FERC ¶ 61,198, at P 74 (2020) 
(“[P]rice suppression was an acceptable byproduct of market rules that would attract new entry through 
greater investor assurance and protect consumers from very high year-one prices.” (citing New Eng. Power 
Generators Ass’n v. FERC, 881 F.3d 202, 209 (D.C. Cir. 2018))); see also ISO New Eng. Inc., 155 FERC 
¶ 61,023, at P 68 (2016) (finding that, where ISO New England Inc. (“ISO-NE”) sought to “balance both the 
harms and the benefits to customers from an exemption that might result in some price suppression,” the 
exemption was just and reasonable because ISO NE “took steps to limit the amount of price suppression” 
and enabled the continued procurement of “sufficient capacity to meet reliability targets”). 
140 July 31 Filing, Transmittal Letter at 57.

49 
leaving PJM short yet again when delayed load arrives.”141  NRG’s protest similarly asserts 
that requiring RBP Resources to offer into the RPM as price takers, particularly after 
interventions that “produced ‘unsustainably low price levels for three delivery years’” cuts 
against the need to prevent capacity prices from “‘crash[ing] to levels that make new 
investments likely unprofitable over the life of the assets.’”142 Constellation and NRG’s 
positions in the above-captioned docket effectively recycle arguments previously made 
with respect to RMR resources that have been consistently and summarily dispatched by 
the Commission. 
Constellation and NRG’s efforts to support their price distortion or suppression 
arguments are likewise unavailing.  Constellation offers expert testimony in support of the 
theory that requiring RBP Resources to offer into the RPM as price takers can distort RPM 
price signals, giving rise to a parade of horribles, particularly when “[a]vailable RBP 
UCAP precedes or exceeds the RBP-Related Load reflected in an RPM Auction.”143  
Similarly NRG relies on expert testimony to argue that requiring “resources with RBP 
commitments [to] offer as price-takers into RPM Auctions for the associated Delivery 
Years ‘is antithetical to creating a normal capacity market.’”144 
As a threshold matter, it is unlikely that a significant portion of the RBP related 
load does not materialize in the same RPM Auction that the committed RBP Resources 
would be offered as price-takers.  Nonetheless, should that occur and a large portion of 
RBP related load somehow does not materialize and is not reflected in the demand curve, 
 
141 Constellation Limited Protest at 4 (footnotes omitted). 
142 NRG Limited Protest at 10 (quoting id., Morris Aff. ¶¶ 29, 31). 
143 Constellation Limited Protest at 4 & n.15 (citing Affidavit of Roy J. Shanker, Ph.D., in Support of 
Constellation (Appendix A) ¶¶ 13-16 (“Shanker Aff.”)). 
144 NRG Limited Protest at 10 (quoting id., Morris Aff. ¶ 25).

50 
it would still be appropriate to include the RBP Resources in the supply curve for the RPM 
Auction as price-takers.  The actual quantity of available supply should be reflected in the 
RPM Auctions.  Excluding available supply, consisting of RBP Resources that loads have 
separately paid for, from the capacity auctions would artificially inflate RPM clearing 
prices and send incorrect market signals to retain excess capacity that may no longer be 
necessary in the unlikely event the RBP related load does not materialize.  In addition, RBP 
Resources are being paid for by LSEs that are responsible for RBP Charges and should not 
be double charged.  Absent requiring RBP Resources to be price-takers in the RPM 
Auctions, the loads that pay for such RBP Resources could be double charged for capacity 
even under the contract for differences approach because if such resources do not clear the 
RPM Auction, there would be no capacity revenues to offset the RBP Charges. 
Moreover, in the context of RMR resources, the Commission has consistently not 
been swayed by expert testimony submitted by proponents of the price 
distortion/suppression theory.  As the Commission has held, such testimony has failed to 
establish that “significant capacity price decreases have occurred in the rest-of-state spot 
market actions, solely as a consequence of the [RMR resources].”145  Indeed, the 
Commission has even held that even if, arguendo, evidence of price suppression did 
demonstrate that the participation of RMR resources receiving must-offer price taker 
treatment suppresses capacity auction clearing prices, that evidence fails to demonstrate 
that the reduction to price is unjust and unreasonable.  The Commission has, in such cases, 
relied on RTOs/ISOs to strike the appropriate balance.146  Furthermore, the Commission 
 
145 Indep. Power Producers of N.Y., Inc. v. N.Y. Indep. Sys. Operator, Inc., 150 FERC ¶ 61,214, at P 67 
(2015) (“IPPNY”), order on reh’g & clarification, 170 FERC ¶ 61,118 (2020). 
146 See, e.g., ISO New Eng., 173 FERC ¶ 61,198 at P 74; see also ISO New Eng., 155 FERC ¶ 61,023 at P 68 
(finding that, where ISO-NE sought to “balance both the harms and the benefits to customers from an

51 
has constantly held that “the price taker design accurately reflects” retained resources’ “low 
going-forward costs.”147  Price-taker offers are consistent with the expected outcome of 
competitive markets because the out-of-market revenue (e.g., cost-of-service RMR 
agreements and RBP Charges) must be accounted for.148  
At bottom, neither Constellation nor NRG provides any reason to depart from well-
established Commission precedent, which has consistently found in favor of RTO/ISO 
proposals that require out-of-market resources to be treated as price takers in capacity 
markets, even over the protests of intervenors lodging arguments similar to those raised by 
Constellation and NRG here. 
2. 
NRG’s assertion that RBP Resources offering into the RPM should 
be subject to an offer floor of $175/MW-day (UCAP) is without 
support and an impermissible attempt to expand the focused 
Minimum Offer Price Rule. 
NRG proposes that imposing an offer floor on RBP Resources will guard against 
the risk that offering RBP Resources as price takers will “depress prices in the RPM 
Auctions” and “undermine the viability of PJM’s capacity market.”149  According to NRG, 
“an offer floor of $175/MW-day (UCAP) apply to offers from resources with RBP 
 
exemption that might result in some price suppression,” the exemption was just and reasonable because ISO 
NE “took steps to limit the amount of price suppression” and enabled the continued procurement of 
“sufficient capacity to meet reliability targets”); PJM Interconnection, 137 FERC ¶ 61,145 at P 209 
(accepting PJM’s proposed approach to self-supply resources in capacity auction finding that “it 
appropriately balances the need to protect against uneconomic entry while also mitigating parties’ concerns 
about having to pay twice for capacity as a result of failing to clear in RPM”); ISO New Eng. Inc., 179 FERC 
¶ 61,139, at P 45 (2022) (finding that ISO-NE had “met its burden to show that the proposed revisions 
appropriately balance the need to mitigate the potential exercise of buyer-side market power against the harms 
of over-mitigation”). 
147 See supra note 144; see IPPNY, 150 FERC ¶ 61,214 at P 66; 2016 NYISO RMR Order, 155 FERC 
¶ 61,076 at P 83. 
148 See supra note 145. 
149 NRG Limited Protest at 12.

52 
commitments equal to the forecasted load does not materialize.”150  NRG furthermore 
claim that the $175/MW-day (UCAP) is appropriate, as it is one-half of the administrative, 
time-limited price collar that is currently in place.   
NRG’s arguments are unavailing.  First, as that price collar has been extended 
through the 2029/2030 Delivery Year, the $175/MW-day (UCAP) price floor will apply to 
RBP Resources as well as all other resources offering into the RPM through the 2029/2030 
Delivery Year.   
Second, in the Delivery Years after the price collar is lifted, NRG’s proposed 
$175/MW-day (UCAP) price floor would effectively expand PJM’s targeted Minimum 
Offer Price Rule (“MOPR”).  There is no reason to do so.  In 2023, the United States Court 
of Appeals for the Third Circuit upheld PJM’s targeted MOPR on grounds that the 
Commission had identified sufficient reasons for departing from a more expanded MOPR, 
including that an expanded MOPR permitted “artificially inflated price [that] will falsely 
signal that new entry is needed or that existing resources should forestall retirement, with 
potentially detrimental effects on PJM’s energy and ancillary service markets.”151 
NRG’s proposal effectively cuts against the Commission’s decision to accept 
“narrowly tailored” MOPRs over more expanded MOPRs.152 As the Commission observed 
in ruling on ISO-NE MOPR reforms, “ISO-NE’s limited renewables exemption [to the 
MOPR rule] reflects the balancing of not paying twice for capacity with the alternative 
 
150 Id. at 12. 
151 PJM Power Providers Grp. v. FERC, 88 F.4th 250, 272 (3d Cir. 2023) (internal quotation marks omitted). 
152 ISO New Eng., 155 FERC ¶ 61,023 at P 36; see also ISO New Eng. Inc., 158 FERC ¶ 61,138 at P 43 (“The 
Commission, in balancing generators’ and customers’ interests, reasonably recognized how these 
developments, over time, have tipped the scales, and accepted a narrowly tailored exemption to reduce the 
likelihood that customers will have to pay for redundant capacity.”).

53 
interest in reducing the potential for price suppression.”153  In fact, the Commission found 
that the ISO-NE MOPR reforms were just and reasonable, notwithstanding any price 
suppressive effects.  The Commission held that the expanded application of the MOPR had 
precluded certain resources from receiving a capacity obligation, which, in turn, sent price 
signals that did not reflect the actual resource mix and interfered with efficient markets, 
ultimately pushing market prices up.154  In other words, in response to arguments that the 
expanded MOPR had been necessary to keep prices from reflecting inaccurately low prices 
and resource scarcity, the Commission held that narrowing the MOPR was necessary to 
prevent inaccurately high prices and potential resource oversupply. 
Third, PJM’s targeted MOPR is focused, in part, on protecting against the exercise 
of buyer-side market power.  NRG has not demonstrated the potential for the exercise of 
buyer-side market power in the RBP.  The RBP is a pay-as-bid procurement, not a single 
clearing-price auction.  In a pay-as-bid auction, sellers of new capacity participating in the 
RBP simply do not have the incentive or ability to suppress or even affect clearing prices 
to benefit their portfolio of load.  The RBP is not a construct that risks enabling buyers to 
exercise market power.   
Fourth, a floor price for RBP Resources set at $175/MW-day is unsupported.  The 
existing MOPR rules provide default CONE and Avoidable Cost Rates for each resource 
class.  It would be inappropriate to establish a uniform floor price for all RBP Resources 
based on the existing floor price used in the price collar that is set to expire after the RPM 
Auctions associated with the 2029/2030 Delivery Year. 
 
153 ISO New Eng. Inc., 173 FERC ¶ 61,161, at P 112 (2020).   
154 Id. P 52.

54 
3. 
It is unnecessary to exclude RBP demand and RBP supply from the 
RPM for purposes of price formation. 
Constellation suggests that “removing the separately procured RBP supply and the 
corresponding RBP-related demand from RPM price formation . . . eliminates the threat of 
any double payment and removes the deleterious impact on RPM.”155  PJM has never 
required that price formation in the RPM turn on perfectly matched demand and supply.  
Indeed, in 2024 PJM proposed, and in 2025, the Commission subsequently accepted, an 
extension of the capacity must-offer requirement to all available Existing Generation 
Capacity Resources.156  
The Commission has approved resource-specific exceptions and categorical 
exemptions to the must-offer requirement in narrow circumstances, when “reasonable and 
sufficiently narrow to prevent withholding.”157  Constellation does not argue that an 
exception to the must-offer requirement for RBP Resources is necessary to prevent 
withholding.  Rather, the crux of Constellation’s argument is simply that a mismatch 
between available RBP UCAP and the timely addition of RBP-related load risks may 
impact price formation and create reliability risks.  But that observation is not dispositive.  
Indeed, similar dynamics exist today in the RPM.  For example, integrated utilities that 
have built more than needed today based on forecasted load growth, such excess supply 
would not be excused from the must offer requirement in the RPM.  As PJM’s IMM, Dr. 
 
155 Constellation Limited Protest at 10-11 (citing id., Shanker Aff. ¶¶ 25-30). 
156 PJM Interconnection, L.L.C., Extending the Capacity Must-Offer Requirement to All Generation Capacity 
Resources of PJM Interconnection, L.L.C., Docket No. ER25-785-000 (Dec. 20, 2024); PJM 
Interconnection, L.L.C., 190 FERC ¶ 61,117, order addressing arguments raised on reh’g, 191 FERC 
¶ 61,221 (2025).  
157 PJM Interconnection, L.L.C., 151 FERC ¶ 61,208 at P 355, order denying request for clarification, 
granting in part request for reh’g, granting in part complaint, & directing compliance filing, 152 FERC 
¶ 61,064 (2015), order on reh’g & compliance, 155 FERC ¶ 61,157 (2016), aff’d sub nom. Advanced Energy 
Mgmt. All. v. FERC, 860 F.3d 656 (D.C. Cir. 2017).

55 
Joseph E. Bowring observed in testimony before the Pennsylvania House of 
Representatives, Environmental Resources and Energy Committee in 2024, “[t]he purpose 
of the RPM must offer rule, which has been in place since the beginning of the capacity 
market in 1999, is to ensure that the capacity market works based on the inclusion of all 
demand and all supply, and to prevent the exercise of market power via withholding of 
supply.”158 
H. 
Arguments That RBP Should Be Extended to FRR Entities Are Baseless. 
East Kentucky Power Cooperative, Inc. (“EKPC”) argues that, because the scope 
of PJM’s proposal does not extend to FRR Entities, the proposal “creates comparability 
concerns and unduly discriminates against RPM Capacity Market LSEs.”159  This 
argument is baseless.  As discussed throughout the July 31 Filing and this Answer, the 
scope of RBP is to procure capacity to meet the resource adequacy needs of new large loads 
that did not bring their own capacity.  This does not implicate FRR Entities.160  By 
definition, FRR Entities must bring new capacity for all new loads within their territory.161  
If an FRR Entity does not include sufficient capacity in its FRR Capacity Plan, the FRR 
Entity is subject to “an FRR Commitment Insufficiency Charge, in an amount equal to two 
 
158 Testimony of Joseph E. Bowring, the Independent Market Monitor for PJM, Pennsylvania House of 
Representatives, Environmental Resources and Energy Committee, Pennsylvania General Assembly, 5 
(Oct. 16, 
2024), 
https://www.palegis.us/house/committees/meeting-archive?MeetingId=4180 
[https://perma.cc/A5XT-SV5W]. 
159 EKPC Protest at 45. 
160 In the July 31 Filing, PJM inadvertently submitted a revision to RAA, Schedule 8.1D, section 1.1:  “An 
FRR Entity may not use an Existing Generation Capacity Resource not owned by such FRR Entity as of 
June 1, 2027 or any resource committed through the Reliability Backstop Procurement to satisfy its Capacity 
FRR Plan.”  PJM did not intend to include this revision as part of the RBP proposal, and did not discuss or 
in any way support this change in the transmittal letter.  Rather, PJM intended to (and did) submit a revision 
in this vein as part of its IRAS proposal in Docket No. ER26-3515-000.  Consistent with PJM’s existing 
consent to the Commission making modifications to the July 31 Filing, PJM requests that the Commission 
reject this specific revision to RAA, Schedule 8.1D, section 1.1 and not accept this revised eTariff record.  
161 See RAA, Article 1 (defining FRR Service Area states that “the FRR Entity has or assumes the obligation 
to provide capacity for all load (including load growth) within such area.”).

56 
times the Cost of New Entry for the relevant location” multiplied by the MW of capacity 
short.162  In contrast, LSEs participating in RPM have no requirement to bring capacity 
sufficient to meet their needs.  Indeed, that is exactly what RBP is designed to do—bring 
new capacity for the new large loads that did not bring their own.  Thus, contrary to EKPC’s 
claim,163 LSEs participating in RPM are not similarly situated to FRR Entities.   
I. 
PJM’s Proposed Cost Allocation Approach Appropriately Assigns Cost 
Responsibility to the Electric Distributor Zone/Areas That Submitted the 
Load Adjustments Driving the Need for the RBP. 
Several parties filed comments regarding PJM’s proposed cost allocation approach.  
As discussed below, representatives for state regulatory bodies generally support PJM’s 
approach, while some of those that would be allocated cost responsibility object.   
1. 
State regulatory bodies, the DCC, and AMP support PJM’s cost 
allocation approach. 
As noted, PJM’s proposal received broad state support—which is significant, as 
state action is necessary to ensure those LSEs serving the data centers and other large loads 
causing the need for the procurement of RBP Resources bear the costs.  OPSI stated 
agreement that “successful implementation of the RBP will require timely retail regulatory 
action that ensures existing retail loads are insulated from or share in the cost of the RBP 
only to the extent consistent with state retail ratemaking approvals.”164  OPSI continued 
that the states’ retail regulators have jurisdiction “to allocate[e] RBP costs to retail 
customers” and that “several states have already begun implementing or considering retail 
ratemaking reforms designed to more closely align the costs associated with new large-
 
162 Id., Schedule 8.1D, section 7. 
163 See EKPC Protest at 46. 
164 OPSI Comments at 2.

57 
load development with those customers.”165  The NJ BPU stated that it “will work closely 
with other state entities and utilities to ensure that these [RBP] costs are properly allocated 
to incoming data centers.”166  The Ohio FEA stated that, “[w]hile the allocation of any 
wholesale costs to retail customers is within the purview of each state, . . . it is widely 
agreed that the costs of the RBP should be paid by the data centers seeking new capacity 
during this time of regional demand/supply constraint.”167  Therefore, “successful 
implementation of the RBP means that, upon Commission approval, states and utilities 
must work expeditiously to align state regulations and cost-allocation frameworks (i.e., 
tariffs) with the RBP structure, as needed, to ensure that the cost of procuring long-term 
capacity under the RBP is appropriately assigned to the cost causers,” i.e., data centers and 
other large loads driving the Load Adjustments.168  Indeed, after PJM submitted this RBP 
proposal, Josh Shapiro issued an executive order to protect Pennsylvania consumers by 
“charg[ing] the appropriate data center customers for any PJM reliability backstop auction 
costs . . . .”169 
PJM’s cost allocation proposal also received support from load interests.  American 
Municipal Power, Inc. (“AMP”) supports PJM’s approach to allocate RBP costs “to those 
Electric Distributor zone/areas that have provided to PJM projections of large load growth 
 
165Id. 
166 NJ BPU Comments at 4. 
167 Ohio FEA Comments at 5. 
168 Id. at 6. 
169 Pa. Exec. Order No. 2026-05, 56 Pa. B. 5902 § 7.1084 ¶ 2(b)(1) (Aug. 18, 2026).

58 
between 2026 and 2028.”170  AMP agrees that PJM’s “allocation framework is consistent 
with cost causation principles and the Ratepayer Protection Pledge.”171 
In addition, the DCC stated that “[t]he costs associated with serving new large loads 
should be borne by new large loads contributing to resource inadequacy and should not be 
shifted to existing residential, commercial, or industrial customers or new large loads that 
have not contributed to resource inadequacy.”172  The DCC also stated that “[s]ignificant 
work will be required at the state level to translate PJM’s wholesale allocation into retail 
tariffs that accurately assign RBP costs to the large loads responsible for the incremental 
demand, while protecting other customers from inappropriate cost shifts.”173   
Retail Energy Supply Association (“RESA”) likewise notes that “[i]f the RBP 
Proposal is accepted substantially as filed, every PJM state—and particularly those open 
to retail competition—will need to move immediately to identify Large Load Customers 
and to assign RBP costs and collateral obligations to those customers and their LSEs.  
RESA intends to participate in those proceedings . . . .”174 
PJM stands ready to assist the states in their efforts to allocate RBP costs to those 
LSEs serving the loads driving the need for the RBP.  Therein fact, PJM and the PJM states 
have been engaging in collaborative efforts to work towards addressing questions raised 
 
170 AMP Comments at 3 & n.6 (citing July 31 Filing, Croop Aff. ¶¶ 41-43; id., Transmittal Letter at 96-97, 
101).   
171 Id. at 3 & n.7 (citing July 31 Filing, Transmittal Letter at 100-08).  In response to AMP’s request, PJM 
clarifies that “Electric Distributor zone/area” used in the proposed RBP Tariff rules holds the same meaning 
as accepted by the Commission in Docket No. ER24-2447.  See July 31 Filing, Transmittal Letter at 100-01. 
172 DCC Comments at 4. 
173 Id. at 5. 
174 RESA Protest at 7.

59 
by intervenors about implementation, including cost allocation under the cooperative 
federalism framework.175   
2. 
LSEs serving new large loads that would be allocated cost 
responsibility present several meritless arguments opposing cost 
responsibility for their new large loads’ contribution to the current 
shortfall. 
PJM’s cost allocation proposal is opposed by those who would be responsible for 
bearing the costs of RBP Resources—data center developers and entities that are 
contracting to serve new large loads.  Specifically, it is opposed by Amazon, Dominion, 
NOVEC, FirstEnergy Service Company (“FirstEnergy”), AEP, and EKPC.  Each of these 
entities (or their parent) is a signatory to the Ratepayer Protection Pledge176 and, as such, 
committed to “build, bring, or buy the new generation resources and electricity needed to 
satisfy their new energy demands, paying the full cost of those resources whether by 
building, or buying from, new or otherwise additive power plants.”177  The RBP is a 
mechanism to bring and buy new generation resources and electricity to meet the demands 
of new large loads.  As discussed below, these parties’ objections to PJM’s cost allocation 
approach are meritless. 
 
175 To the extent that some intervenors have requested that additional or enhanced information sharing with 
state entities and affected loads, PJM notes that it will adhere to existing information sharing and 
confidentiality provisions.  
176 
Data 
centers 
pay 
their 
way. 
Ratepayers 
pay 
theirs., 
The 
White 
House, 
https://www.whitehouse.gov/ratepayer-protection-pledge/ [https://perma.cc/3WBQ-RXW4] (last visited on 
Sep. 8, 2026) (“White House Ratepayer Protection Pledge Signatories”) (listing all 317 signatories). 
177 
Ratepayer 
Protection 
Pledge, 
The 
White 
House 
(Mar. 
4, 
2026), 
https://www.whitehouse.gov/releases/2026/03/ ratepayer-protection-pledge/ [https://perma.cc/N8PH-K82T] 
(“Ratepayer Protection Pledge”).

60 
a. 
The procurement target is appropriately based on a snapshot 
of the RTO-wide shortfall observed in the 2028/2029 BRA. 
AEP and Amazon claim that allocating RBP cost responsibility based on current 
cost causation over the 15-year term of the RBP commitment is unjust and unreasonable.178  
The Commission can easily dismiss this argument.  As an initial matter, this is not a claim 
that the new large loads did not cause the need for the capacity procured through the RBP, 
but rather an argument over whether they should have to pay for the capacity for the entire 
capacity commitment term.179  In this context, the answer is yes.   
The Commission has long held that relying on snapshots is an acceptable and 
appropriate method for establishing baselines or targets,180 and the objections raised herein 
have provided no reason for the Commission to depart from that precedent—particularly 
where PJM has proposed a conservative figure based on an RTO-wide procurement target, 
 
178 See AEP Limited Protest at 29-30. 
179 AEP’s other argument against allocating costs based on the Load Adjustments driving the shortfall is more 
tenuous.  AEP appears to argue that because the proposed RBP is not procuring RBP Resources on a 
locational basis, allocating the costs to the Electric Distributor zone/area with Load Adjustments is unjust 
and unreasonable.  AEP Limited Protest at 29.  This argument ignores that the RBP is designed to address 
the regional shortfall driven by these large loads, not the need for locational capacity driven by transmission 
constraints.  As the Commission well understands, all capacity in PJM is deliverable to all loads in PJM until 
transmission constraints are met.   
180 See, e.g., Joint Consumer Representatives v. PJM Interconnection, L.L.C., 153 FERC ¶ 61,187, at P 32 
(2015) (denying complaint and reasoning that “[w]hile there will inevitably be some difference between 
PJM’s load forecast and the amount of capacity that PJM ultimately needs in a given Delivery Year, the 
record indicates that PJM has taken steps to ensure the reasonableness of the 2015 Load Forecast, including 
making a statistical adjustment, based on a percentage of error it had seen in the load forecast over recent 
years, to account for the effects of energy efficiency programs.” (citation omitted)); see also PJM 
Interconnection, L.L.C., 162 FERC ¶ 61,136, at P 24 (2018) (rejecting Dominion’s proposal to revise PJM’s 
Tariff “to incorporate an average demand feature into how it determines a transmission customer’s 
contribution to Network Service Peak Load.  Dominion argues that such a feature is necessary because, 
without it a single transmission customer could shift costs to other customers since the billing determinants 
are otherwise calculated using a single-hour snapshot of customer demand each year.”); Del. Pub. Serv. 
Comm’n v. PJM Interconnection, L.L.C., 166 FERC ¶ 61,161, at P 46 (2019) (finding that “based on the 
record developed here regarding the stability-related reliability issue category, we do not find the limitations 
of a snapshot analysis to be sufficiently problematic to alter our conclusion that the Stability Deviation 
Method is just and reasonable”); BP W. Coast Prods., LLC v. SFPP, L.P., 121 FERC ¶ 61,141, at P 6 (2007) 
(noting that the “screening approach at the suspension phase is a snap shot approach that avoids extensive 
arguments over issues of accounting accuracy and rate reasonableness within the time limits available for 
Commission review, and highlights the simplicity of the filing procedure”).

61 
intended as an initial step that will kick-start PJM’s efforts to procure sufficient to capacity 
to support the needs of the region. 
The PJM Region is experiencing a capacity shortfall that can be directly attributed 
to the Load Adjustments submitted to PJM by entities in the Electric Distributor zone/areas 
that would be allocated RBP cost responsibility—and AEP and Amazon do not allege 
otherwise.  Rather, they state the unremarkable fact that load growth patterns change over 
time.181  The RBP is a one-time procurement of new capacity resources to address the 
resource adequacy needs of the Load Adjustments submitted for the Electric Distributor 
zone/areas.  This squarely meets the requirement that “costs must be allocated consistent 
with cost causation principles.”182 
Moreover, establishing the procurement target based on a snapshot of the 
RTO-wide shortfall for the term of the RBP commitment provides certainty to that 
zone/area on the quantity of RBP MW that the loads will be responsible for paying, while 
still providing the flexibility for RERRAs to update LSE cost allocation during the term of 
such commitment.  This would allow LSEs to make long-term plans for such RBP Charges, 
including arrangements to post collateral, and avoid scenarios where new load bilaterally 
contracts for new capacity but subsequently gets allocated RBP Charges. 
b. 
PJM’s proposed cost allocation approach appropriately 
assigns RBP Charges to the zones/areas with reported new 
load that is not matched with new capacity. 
NOVEC argues that “PJM has not adequately demonstrated why the incremental 
costs and substantial credit obligations associated with RBP Resources should be 
 
181 See AEP Limited Protest at 29; Amazon Comments at 4-5. 
182 Entergy Servs., LLC, 196 FERC ¶ 61,166, at P 25 (2026) (citing N. States Power Co., 64 FERC ¶ 61,324, 
at 63,379 (1993) (“[T]he fundamental principle of cost causation [is] that costs should be recovered in the 
rates of those customers who utilize the facilities and thus cause the cost to be incurred.”)).

62 
concentrated on designated RBP buyers without accounting for material capacity-market 
benefits those resources may provide to other PJM load.”183  The Commission should reject 
this argument.  NOVEC seeks to establish a false standard for cost allocation approaches.   
As the Commission is well aware, the cost causation principle requires that costs 
be allocated “at least roughly commensurate” with the benefits.184  This means that “all 
approved rates reflect to some degree the costs actually caused by the customer who must 
pay them.”185  To the extent an entity causes the costs to be incurred, it will have to pay its 
share.  Importantly, consistent with the “roughly commensurate” principle, “nothing 
requires the Commission to ensure full or perfect cost causation,”186 and the Commission 
“is not bound to reject any rate mechanism that tracks the cost causation principle less than 
perfectly.”187   
PJM’s proposed approach easily meets this standard.  As PJM explained in the 
July 31 Filing, “PJM has tracked Load Adjustments in zones/areas to the level of 
granularity that is feasible,”188 “based on equations that ‘allow PJM to allocate a capacity 
obligation associated with a load adjustment to the zone/area in which the adjustment 
occurs.’”189  PJM’s approach relies on the best information available and properly allocates 
costs to those Electric Distributor zone/areas with Load Adjustments (that were requested 
by the Electric Distributor or LSE).  The result is a cost allocation methodology that assigns 
 
183 NOVEC Protest at 16. 
184 Ill. Com. Comm’n v. FERC, 576 F.3d 470, 477 (7th Cir. 2009).   
185 KN Energy Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992). 
186 S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 88 (D.C. Cir. 2014).    
187 Sithe/Indep. Power Partners, L.P. v. FERC, 285 F.3d 1, 5 (D.C. Cir. 2002) (citation omitted).  
188 July 31 Filing, Transmittal Letter at 103. 
189 Id. at 102 (quoting PJM Interconnection, L.L.C., 188 FERC ¶ 61,200, at P 37 (2024)).

63 
cost responsibility to the zones/areas with reported new load that is not matched with new 
capacity—i.e., the zones/areas and LSEs can be said to have caused the target resource 
adequacy shortfall.   
However, to be clear, PJM has taken its approach as granular as it can go.  PJM is 
allocating costs to specific zones, but the allocation to large loads within an Electric 
Distributor’s zone/area is a matter of retail allocation for the states, consistent with the 
NEDC/PJM Governors’ Principles.190  As the DCC stated, “[u]ltimately, the RBP’s cost-
allocation framework should accomplish a straightforward objective: large loads should 
pay the costs associated with serving their incremental demand, receive appropriate credit 
when they bring new capacity to meet that demand, and existing customers should not be 
left with the bill.”191 
In any event, while there could be alternative cost allocation approaches, that may 
also be just and reasonable, that does not mean PJM’s proposal is not just and reasonable.192   
c. 
To be just and reasonable, PJM’s cost allocation approach 
does not need to allocate costs to data centers specifically. 
FirstEnergy contends that “PJM’s cost allocation proposal is not meaningfully 
targeted to ensure the customers ultimately allocated the costs of the RBP will be entities 
 
190 The governors of the 13 states in the PJM Region committed to “[u]se all available authorities to ensure 
that their state public utility commissions design rate class structures to ensure that their states' LSEs allocate 
their share of the cost to procure new capacity through the Reliability Backstop Auctions to new data center 
loads that have not otherwise procured capacity or agreed to be curtailable.”  NEDC/PJM Governors’ 
Principles at 2. 
191 DCC Comments at 6. 
192 See, e.g., Cities of Bethany, 727 F.2d at 1131 (“FERC has interpreted its authority to review rates under 
[the FPA] as limited to an inquiry into whether the rates proposed by a utility are reasonable—and not to 
extend to determining whether a proposed rate schedule is more or less reasonable than alternative rate 
designs.” (citing Pub. Serv. Co. of Ind., 56 FPC 3003 (1976)); Midwest Indep. Transmission Sys. Operator, 
Inc., 127 FERC ¶ 61,109, at P 20 (2009) (“It is well established that there can be more than one just and 
reasonable rate . . . .” (citing Am. Elec. Power Serv. Corp. v. Midwest Indep. Transmission Sys. Operator, 
Inc., 122 FERC ¶ 61,083, at P 88, order on reh’g, 125 FERC ¶ 61,342 (2008))).

64 
causing the need for the procurement of new generation—i.e. new data center customers, 
in accordance with the [NEDC/PJM Governors’ Principles].”193  The basis for this 
contention is that PJM did not identify specific data centers but instead is relying on the 
Electric Distributor / LSE submitted Load Adjustments, and that such Load Adjustments 
“are not limited to new data centers.”194  It is fallacious to suggest that a just and reasonable 
cost allocation approach must either identify specific loads (which are not 
FPA-jurisdictional actors) and not the LSEs serving those loads or be limited to one type 
of load when the resource adequacy shortfall is caused by all types of loads that comprise 
the subject Load Adjustments.  Further, as PJM explained in the July 31 Filing,195 the 
concept of Load Adjustments was added in 2024 “to better allocate, to zones/areas, 
localized load adjustments used to determine capacity obligations for [LSE]”196 and were, 
as PJM noted at the time, “spurred by the recent proliferation of data centers that are 
contributing to large additions of forecasted load concentrated within a specific wholesale 
metering area.”197  The Load Adjustments allow for “more accurate[] assign[ment of] 
capacity obligations to LSEs.”198  Finally, in the NEDC/PJM Governors’ Principles, the 
governors of PJM states committed to “to ensure that their states’ LSEs allocate their share 
of the cost to procure new capacity through the [RBP] to new data center loads that have 
not otherwise procured capacity or agreed to be curtailable.”199  Thus, it is appropriate for 
 
193 FirstEnergy Comments and Protest at 12.  
194Id. 
195 See July 31 Filing, Transmittal Letter at 100-01. 
196 PJM Interconnection, 188 FERC ¶ 61,200 at P 1. 
197 PJM Interconnection, L.L.C., Proposal to Better Account for Large Load Adjustments in Forecasted 
Capacity Obligations of PJM Interconnection, L.L.C., Docket No. ER24-2447-000, at 1 (July 1, 2024). 
198 Id. 
199 NEDC/PJM Governors’ Principles at 2.

65 
PJM to rely on the individual states to ultimately allocate the RBP Charges to the new data 
center loads on the retail level in accordance with the NEDC/PJM Governors’ Principles. 
d. 
Claims that RBP cost allocation would affect existing 
commercial arrangements are unsupported and speculative. 
FirstEnergy asserts that PJM’s allocation of cost responsibility “violates the filed 
rate doctrine because it will undermine preexisting commercial relationships by attempting 
to allocate costs to data centers who possibly have already signed FERC-jurisdictional 
contracts based on a pre-RBP understanding of the market.”200  This assertion is fatally 
flawed.   
First, FirstEnergy fails to support it.  FirstEnergy cites no “FERC-jurisdictional 
contracts” which would be public, to the extent they exist, that would be “undermined.”  
Thus, it is not possible to discern which filed rate would be violated.  Relatedly, FirstEnergy 
presents this as something that is “possible” not actual.  Thus, even taking the claim as 
asserted by FirstEnergy, it is speculative.   
Second, each contract is an exercise in risk allocation between the parties to that 
contract.  For years, it has been well understood that the PJM Region would soon be facing 
a capacity shortfall.201  
 
200 FirstEnergy Comments and Protest at 13. 
201 See, e.g., PJM Interconnection, L.L.C., Revisions to Reliability Pricing Model, Docket No. 
ER25-682-000, Transmittal Letter at 5 (Dec. 9, 2024) (“PJM expects the rapid tightening of supply and 
demand trends to continue for the foreseeable future.  Indeed, PJM expects load growth to continue to further 
increase even in the upcoming 2026/2027 Base Residual Auction, driven in large part by electrification trends 
and data center development in the PJM Region. Preliminary 2025 load forecast indicates a load increase of 
2,700 MW for the 2026 Delivery Year compared with the 2024 load forecast for the same 2026 Delivery 
Year.”); Tim Horger & Adam Keech, 2025/2026 Base Residual Auction Results, PJM Interconnection, 
L.L.C., 
30 
(Aug. 
21, 
2024), 
https://pjm.com/-/media/committees-
groups/committees/mrc/2024/20240821/20240821-item-08---2025-2026-base-residual-auction---
presentation.ashx [https://perma.cc/5WBB-WFAW] (In the 2025/2026 BRA, the market’s supply and 
demand converged to the point where only 514 MW of annual UCAP was offered above the PJM Region 
Reliability Requirement in the 2025/2026 BRA.); Energy Transition in PJM: Resource Retirements, 
Replacements & Risks, PJM Interconnection, L.L.C., 17 (Feb. 24, 2023), https://www.pjm.com/-
/media/library/reports-notices/special-reports/2023/energy-transition-in-pjm-resource-retirements-

66 
Since at least April 2025, there has been discussion about the need for an out-of-
RPM mechanism to address the resource adequacy shortfall caused by new large loads—
including through a load reduction service for non-capacity backed loads202 or through an 
“enhanced” RPM reliability backstop mechanism “to mitigate potential for acute reliability 
risks” as advocated by the Brattle Group in the 2025 VRR Curve periodic review 
process.203  Notably, the cited notices of potential future action on large loads occurred 
before or contemporaneous with Electric Distributors’ and LSEs’ submission of their fall 
of 2025 Load Adjustment requests to PJM204—the Load Adjustments included in the 2026 
Load Forecast and that comprise the Initial RBP Target. 
Given this, LSEs and large loads should have been on notice that change was 
coming, and as sophisticated parties, they would have priced and valued in their contractual 
negotiations the risk of how the PJM Region and the Commission would address the 
impacts of large loads causing the resource adequacy shortfall.  Given that these are not 
pro forma arrangements, the means for allocating risk would be idiosyncratic to each 
 
replacements-and-risks.ashx. [https://perma.cc/8UGM-9MNT ] (In light of these uncertainties, PJM’s 2023 
whitepaper emphasized the importance of “[m]anaging the energy transition through collaborative efforts of 
PJM stakeholders, state and federal agencies, and consumers” in order to “ensure PJM has the tools and 
resources to maintain reliability.”). 
202 Tim Horger, Large Load Additions, PJM Interconnection, L.L.C. (Sep. 15, 2025), https://www.pjm.com/-
/media/DotCom/committees-groups/cifp-lla/2025/20250915/20250915-item-07---pjm-initial-proposal-and-
alternatives-considered---pjm-presentation.pdf [https://perma.cc/63JH-37Q2]. 
203 Kathleen Spees, et al., Sixth Review of PJM’s Variable Resource Requirement Curve for Planning Years 
2028/29 Through 2031/32, Brattle Group, 11 (Apr. 9, 2025), https://www.brattle.com/wp-
content/uploads/2025/04/Sixth-Review-of-PJMs-Variable-Resource-Requirement-Curve.pdf 
[https://perma.cc/DT9F-FJ32]. 
204 For information about the Load Adjustments submitted in 2025 for the 2026 Load Forecast, see the 
meeting materials posted for the September 16, 2025 Load Analysis Subcommittee meeting.  See Load 
Analysis 
Subcommittee, 
PJM 
Interconnection, 
L.L.C., 
https://www.pjm.com/committees-and-
groups/subcommittees/las [https://perma.cc/2327-9PJB] (last visited Sep. 10, 2026); see Load Analysis 
Subcommittee, Agenda, PJM Interconnection, L.L.C. (Sep. 16, 2025), https://www.pjm.com/-
/media/DotCom/committees-groups/subcommittees/las/2025/20250916/20250916-agenda.pdf 
[https://perma.cc/38XS-EZB4].

67 
contract.  In any event, to the extent the RBP was not contemplated by the parties, the 
benefits of RBP—and the RBP UCAP MW—also were not contemplated.  Thus, allocation 
of RBP Charges corresponding to such benefit would be just and reasonable. 
Finally, to the extent an existing arrangement may be affected by PJM’s proposed 
RBP cost allocation, the extent to which any deal may be affected is necessarily a 
contract-specific inquiry.   
e. 
PJM’s proposed cost allocation rules appropriately invite 
state input on allocating costs to specific retail customers. 
EKPC broadly objects to PJM’s cost allocation approach, and the Kentucky 
Attorney General, in support of EKPC, notes that “[o]f particular concern is whether Load 
Serving Entities who have met their obligations are protected from cost allocation in the 
event of default by the cost causer.”205  EKPC raises concerns about state regulatory bodies 
electing whether to reallocate cost responsibility, with the root of the concern apparently 
focused on uncertainty about whether the state regulator will act and if so, how.206   
 
205 Kentucky Attorney General Answer at 2.  To be clear, under PJM’s proposal, in no event would EKPC 
be allocated any cost responsibility.  EKPC would not be allocated any cost responsibility for RBP Charges, 
as the EKPC Transmission Zone and Electric Distributor zone/area did not have any Load Adjustment MW 
for the 2026 to 2028 period.  2026 PJM Load Forecast Report Data Tables, PJM Interconnection, L.L.C., 
Tab Table B9b (Feb. 2026), https://www.pjm.com/-/media/DotCom/planning/res-adeq/load-forecast/2026-
load-report-tables.xlsx [https://perma.cc/SST2-EGUZ]; 2026 PJM Load Forecast Report, PJM 
Interconnection, L.L.C., 5-6 (Jan. 14, 2026), https://www.pjm.com/-/media/DotCom/library/reports-
notices/load-forecast/2026-load-report.pdf [https://perma.cc/J24E-7CV7] (describing Table B9b results).  In 
fact, under PJM’s proposal, EKPC would not be allocated any cost responsibility in the event of default by 
another LSE on paying RBP Charges, as PJM’s proposal would require such reallocation of cost 
responsibility among other LSEs already paying RBP Charges.  See July 31 Filing, proposed Tariff, 
Attachment DD, section 18.9(a) (“In the event a Load Serving Entity defaults and fails to pay an RBP Charge, 
the defaulted amount will be allocated to all remaining Load Serving Entities responsible for paying RBP 
Charges based on their pro-rata share of the total RBP Charges for all such Load Serving Entities.  Such 
amounts may be offset by the RBP Collateral posted by the defaulting Load Serving Entity.”).   
206 See EKPC Protest at 17 (“The uncertainty of being assigned costs, as well as the magnitude of the costs 
that may be assigned, should the large loads not materialize in each zone/area as PJM anticipated in 
establishing the procurement target, will itself impact whether large loads materialize as forecasted.”).

68 
PJM’s proposal is just and reasonable in this regard—and consistent with the stated 
commitments of all 13 governors in the PJM Region.  As explained in the July 31 Filing, 
PJM’s proposal follows the Commission’s lead by respecting the boundary between state/ 
RERRA and federal jurisdiction.207  It is the PJM states and/or RERRAs that “have 
authority over how the wholesale costs of providing electricity, including transmission of 
such electricity, to those retail customers are recovered through retail rates.”208  To achieve 
the goal of allocating RBP Charges to the data centers and other large load, the states’ line 
of sight into the retail customers and their LSEs—line of sight PJM does not have—will 
be vital.  Thus, a cost allocation methodology that provides the PJM states and/or RERRAs 
with the ability to determine how to allocate RBP Charge to LSEs within a given Electric 
Distributor zone/area, as well as to cost allocate to end-use customers in their respective 
states in accordance with their laws and policies, supports each PJM state governor’s 
pledge in the NEDC/PJM Governors’ Principles, including the principle that the cost of 
new capacity should be allocated to data centers who have caused the need for additional 
capacity in the PJM Region.209   
EKPC also argues against the default allocation approach, which would only apply 
if a relevant state elects not to act.  Specifically, EKPC argues that “PJM has failed to 
provide clear and transparent procedures to allow an LSE to determine the amount of costs 
it may be allocated under the PJM RBP proposal”210 and that “[t]his backup methodology 
 
207 See July 31 Filing, Transmittal Letter at 104-08. 
208 PJM Interconnection, 195 FERC ¶ 61,211 at P 69 (citing PJM Interconnection, L.L.C. v. PJM 
Interconnection, L.L.C., 190 FERC ¶ 61,115, at P 68 (2025)). 
209 NEDC/PJM Governors’ Principles at 1. 
210 EKPC Protest at 17 (internal quotation marks omitted).

69 
socializes RBP costs across all load within the zone—including LSEs serving customer 
bases that contributed nothing to the capacity shortfall.”211 
First, PJM’s proposed rules very clearly delineate how an LSE may be allocated 
responsibility for RBP Charges in the unlikely event that the applicable state regulatory 
body fails to weigh in.  As PJM has previously explained, the default method of allocation 
exists only as a safeguard against the unlikely event that a state regulatory body fails to act. 
Should that default methodology be needed, LSEs in Electric Distributor zone/areas 
to which some quantity of Load Adjustments have been assigned would be allocated cost 
responsibility in the same way that cost responsibility is allocated to LSEs in the RPM.212  
As such, the backup method of allocation under the RBP, relied on only if state regulatory 
bodies fail to act, is an established, clear and transparent methodology.  
Second, in the absence of state coordination, PJM will not have the granular 
information needed to assign cost responsibility to the LSEs serving the retail load that 
gave rise to the Load Adjustment.  While the Load Adjustment process does allow PJM to 
receive some data about which LSE is serving load, this does not necessarily mean that 
PJM will have all the necessary data in every instance.  Thus, under such circumstances, 
should they arise, spreading the responsibility for RBP Charges pro-rata across an Electric 
Distributor zone/area would be a reasonable method to fall back on.   
 
211 Id. at 20. 
212 See July 31 Filing, proposed Tariff, Attachment DD, section 18.3(b)(iii) (“If no [RBP Obligation] MW 
are reported to the Office of the Interconnection in an Electric Distributor zone/area, PJM will allocate the 
RBP Charges for that zone/area to all load in the zone/area using each LSE’s ratio share of the Daily Unforced 
Capacity Obligation for the zone/area as determined in RAA, Schedule 8.”).

70 
f. 
Because RBP is driven by the need for all new large loads to 
bring their own capacity, to avoid RBP Charges, an Electric 
Distributor zone/area must fully offset its Load Adjustment 
MW. 
Dominion asserts that PJM’s approach to crediting an Electric Distributor zone/area 
for Qualifying RBP Offset UCAP MW is unjust and unreasonable because, for cost 
allocation purposes, PJM counts Qualifying RBP Offset UCAP MW against the Electric 
Distributor zone/area’s MW of Load Adjustments, and not against that zone/area’s 
allocated portion of the Initial RBP Target.213  While Dominion’s argument may, at first, 
appear to have some surface appeal, a closer examination reveals that Dominion’s position 
would not support the overarching policy driving the RBP, the NEDC/PJM Governors’ 
Principles, and the Ratepayer Protection Pledge:  All new large loads should pay for new 
capacity and their effects on the transmission system; conversely, existing loads should not 
bear the costs to connect and serve large loads.  Insulating existing ratepayers from the new 
and expansive demands placed on the region by the recent influx of new large loads is at 
the heart of the NEDC/PJM Governors’ Principles and the Ratepayer Protection Pledge.  
Naturally, this primary driver of the RBP animates PJM’s proposed cost allocation 
methodology.  PJM’s approach to determining how an Electric Distributor zone/area may 
eliminate its RBP obligation is grounded in this overarching policy, as explained below. 
First, while the RBP targets a 6,831.3 MW shortfall, it is the Load Adjustments that 
drive the need for the RBP and therefore drive cost allocations to each Electric Distributor 
zone/area.  Table 1 below shows the total Load Adjustments submitted for each Electric 
Distributor zone/area for 2026 through 2028.  Table 1 was initially presented by PJM at 
the third post-filing stakeholder workshop, held August 28, 2026, to discuss RBP 
 
213 See Dominion Partial Protest and Comments at 5-7.

71 
implementation of the RBP,214 and it is a more detailed version of the table submitted in 
Ms. Croop’s affidavit.215  The Load Adjustments values during this period total 
9,033.2 MW.  Broadly speaking, these MW represent new large loads that are expected to 
come to the PJM Region and, until PJM receives their Qualifying RBP Offset UCAP MW 
submissions, have not brought any new capacity.   
Table 1: 2026-2028 Load Adjustment MW by Electric Distributor zone/area216 
 
As Ms. Croop explained, “[t]he initial allocation of RBP UCAP MW to each 
Electric Distributor zone/area will be based on Load Adjustments . . . and each zone/area’s 
share of the Initial RBP Target of 6,831.3 MW.”217  In other words, an Electric Distributor 
zone/area’s MW of Load Adjustment represents that zone/area’s contribution to the need 
 
214 August 28, 2026 RBP Execution Presentation at 7.  For a complete list of all Electric Distributor 
zone/areas, even those with zero Load Adjustment MW between 2026-2028, see PJM’s presentation at the 
second post-filing stakeholder workshop.  PJM Staff & Charles River Associates, Reliability Backstop 
Procurement Execution, PJM Interconnection, L.L.C., 11 (Aug. 10, 2026), https://www.pjm.com/-
/media/DotCom/committees-groups/cifp-rbp/2026/20260810/20260810-pjm-and-cra-reliability-backstop-
procurement-presentation.pdf [https://perma.cc/3URZ-SUXW]. 
215 July 31 Filing, Croop Aff. ¶ 46. 
216 August 28, 2026 RBP Execution Presentation at 7.  
217 July 31 Filing, Croop Aff. ¶ 46.

72 
for the RBP.  The projected influx of new load, as represented by the Load Adjustment 
MW generally caused the resource adequacy shortfall for the 2028/2029 Delivery Year. 
Only by eliminating their Load Adjustment MW value can an Electric Distributor 
zone/area eliminate its responsibility for RBP Charges.  Put another way, the UCAP MW 
figures in the far-right column of Table 1 represent each Electric Distributor zone/area’s 
allocation of the Initial RBP Target.  These figures are the result of applying an Electric 
Distributor zone/area’s proportional share of the total 9,033.2 MW Load Adjustment to the 
identified 2028/2029 Delivery Year shortfall.  In other words, each Electrical Distributor’s 
initial allocation of the RBP target does not represent its proportional responsibility for the 
RBP; rather, it is a function of its proportional responsibility (i.e., it is a mathematically 
derived value resulting from multiplying its proportional share of the total Load 
Adjustment MW by the Initial RBP Target value).  Each Electric Distributor zone/area’s 
proportional share of the total Load Adjustment MW is a means of capturing the 
zone/area’s proportional share of the influx of new large load that is projected to come 
online in the near future.  That influx of new load can be said to have caused the need for 
the RBP.   
With this understanding and context, it becomes clear that Dominion’s critique of 
PJM’s default method for allocating RBP Charges misses the mark.  First, Dominion claims 
that “[r]equiring [Electric Distributor] zone/areas to offset their entire MW Load 
Adjustment Share to avoid having an RBP Obligation raises the possibility that they will 
pay for redundant capacity, which is unjust and unreasonable.”218  The fact is that the Load 
Adjustment represents the quantity of new large loads that have not brought new capacity, 
 
218 Dominion Partial Protest and Comments at 6.

73 
and each Electric Distributor zone/area’s share of the Load Adjustment represents that 
zone/area’s responsibility for the shortfall giving rise to the RBP.   
Nevertheless, PJM proposed that new loads in a zone/area can be demonstrated to 
have since brought new capacity by being matched with Qualifying RBP Offset UCAP 
MW.  Thus, the Initial RBP Target may be decremented by the quantity of Qualifying RBP 
Offset UCAP MW.  Such a requirement does not lead to “redundant capacity;” it leads to 
new capacity serving new large loads.  Qualifying RBP Offset UCAP MW can extinguish 
the Electric Distributor zone/area’s contribution to the need for the RBP.  Further, requiring 
all new large loads to “build, bring, or buy the new generation resources and electricity 
needed to satisfy their new energy demands” is required by the Ratepayer Protection Pledge 
and allows all existing capacity resources to be available to serve non-new large loads. 
Dominion also argues that PJM’s approach could result in some LSEs/new large 
loads in some Electric Distributor zone/areas bringing on sufficient new capacity to 
eliminate the entirety of the Final RBP Target such that load in Electric Distributor 
zone/areas “that did not bring RBP Offsets will still have remaining MW Load Adjustment 
Shares but will not bear any financial consequences for not bringing RBP Offsets because 
[the] Final RBP Obligation will be 0 MW[.]”219  The fact that the actions of some LSEs or 
loads may reduce the RBP obligations of others is not inherently unjust and unreasonable.  
The diffuse benefit from pooled resources is a key feature of being in an RTO.  Further, to 
the extent some LSEs and/or new large loads in some Electric Distributor zone/areas were 
to zero-out the entirety of the Initial RBP Target by bringing on sufficient new capacity to 
meet that target, LSEs and/or new large loads in Electric Distributor zone/areas with Load 
 
219 Id. at 7.

74 
Adjustment MW not matched with new capacity would be foreclosed from being assigned 
cost responsibility through the RBP.  However, those LSEs and/or new large loads would 
nevertheless still be required to bring new capacity or provide IRAS, outside of the RBP 
framework.   
J. 
PJM Appropriately Tailored the Buyer-Side Credit Requirement to the 
15-year Forward Risk Presented By the RBP Commitments So As to 
Protect Ratepayers from Bearing Costs for RBP Resources. 
1. 
PJM’s buyer-side (LSE) collateral requirement is appropriately 
designed to protect ratepayers from exposure to RBP Charges and 
ensure large loads bear RBP Resource costs, as required by the 
Ratepayer Protection Pledge and NEDC/PJM Governors’ 
Principles, and consistent with PJM’s existing credit rules. 
A handful of entities take issue with PJM’s proposal to require those LSEs who 
contributed to the current resource adequacy shortfall that RBP is designed to address to 
post collateral for the purpose of protecting all other ratepayers in PJM from bearing the 
costs of RBP Resources.220  One protestor questions “why it is necessary to require LSEs 
to post additional collateral” to cover their 15-year RBP charge obligation, asserting that 
“there is no justification for imposing new and onerous collateral requirements on LSEs,” 
“[b]ecause retail customers ultimately will pay the RBP costs.221   
While PJM understands that arguments can be made over the amount of collateral 
required, the basic need for a collateral requirement should not be controversial.  Imposing 
a credit requirement for the purpose of ensuring only those entities assigned cost 
responsibility for RBP Resources bear the burden of such costs protects “those LSEs not 
 
220 See NOVEC Protest at 19-24; EKPC Protest at 21-28; FirstEnergy Comments and Protest at 7-9; Equinix 
Comments at 14-16.  No party challenges PJM’s proposed RBP Seller credit requirement.  Equinix describes 
it in passing.  See Equinix Comments at 14.  EKPC’s affiant, Carl F. Coscia, Ph.D., offers criticisms about 
the process but not the merits.  See EKPC Protest, Affidavit of Carl F. Coscia (Attachment 2) ¶¶ 182-84. 
221 FirstEnergy Comments and Protest at 7-8.

75 
allocated cost responsibility for RBP Resources from having to pay for such resources.” 222  
This is consistent with the purpose of PJM’s existing credit rules, which the Commission 
has recognized is to “protect the integrity of the PJM-administered markets, as well as 
protect market participants from financial losses that result from unreasonable credit risks 
and defaults.”223  PJM’s proposal implements the NEDC/PJM Governors’ Principles and 
Ratepayer Protection Pledge by “allocat[ing] the cost of any new capacity procured through 
the . . . Reliability Backstop [Procurement] to load serving entities (LSEs) with new data 
centers,”224 so as to “protect American consumers from price hikes due to data center 
energy and infrastructure requirements, and lower electricity costs for consumers in the 
long term.”225 
Indeed, PJM designed RBP to provide a key role for the states, consistent with their 
governors’ commitment in the NEDC/PJM Governors’ Principles to “use all available 
authorities to ensure that their state public utility commissions . . . ensure that their states’ 
LSEs allocate their share of the cost to procure new capacity through the Reliability 
Backstop [Procurement] to new data center loads,” i.e., the loads that comprise the Load 
Adjustments driving the current capacity shortfall.226  The NJ BPU, for one, recognizes the 
important role the state will have in ensuring RBP costs (including costs associated with 
credit requirements) are properly allocated.  In its comments supporting PJM’s proposal, 
the NJ BPU correctly observes that “[i]n theory, an LSE would pass on the collateral costs 
to the large load, but there may need to be additional forcing mechanisms [at the state level] 
 
222 July 31 Filing, Transmittal Letter at 114. 
223 PJM Interconnection, L.L.C., 171 FERC ¶ 61,173, at P 36 (2020). 
224 NEDC/PJM Governors’ Principles at 1 (emphasis omitted). 
225 Ratepayer Protection Pledge.  
226 NEDC/PJM Governors’ Principles at 2.

76 
in restructured states where retail choice and default service has been the assumed retail 
system.”227  The NJ BPU continues that the proposed “collateral requirement will put 
pressure on the retail-jurisdictional authorities to ensure the collateral obligation does not 
fall upon ratepayers.”228  PJM shares this objective of acting to prevent ratepayers from 
bearing RBP costs, and stands ready to work with the states to develop all appropriate 
mechanisms so that large loads bear all RBP costs. 
Finally, contrary to protestors’ claims otherwise,229 PJM’s proposal also is 
consistent with cost causation principles,230 as the LSEs serving the new load captured by 
the Load Adjustments for which PJM was unable to procure capacity in the 2028/2029 
BRA are the entities that caused the need for the RBP and the entities to be allocated 
responsibility to pay RBP Charges.  Given that the credit requirements apply only to those 
LSEs allocated responsibility for RBP Charges, the credit obligation is directly tied to the 
entity from whom there is default risk exposure, thus appropriately protecting all other 
entities from paying RBP Charges. 
2. 
PJM’s proposed RBP credit requirement is not duplicative of any 
existing PJM credit rule but, rather, is tailored to the long-term 
obligation to pay RBP Charges, which is unlike any current payment 
obligation in PJM’s market rules.  
EKPC and NOVEC both claim that this collateral is “duplicative” of the Peak 
Market Activity collateral PJM requires with regard to, generally speaking, a Market 
Participant’s transaction activity in PJM’s capacity, energy, and ancillary services markets 
 
227 NJ BPU Comments at 5-6. 
228 NJ BPU Comments at 6. 
229 See, e.g., NOVEC Protest at 10; EKPC Protest at 28. 
230 See N. States Power Co., 64 FERC ¶ 61,324, at 63,379 (“[T]he fundamental principle of cost causation 
[is] that costs should be recovered in the rates of those customers who utilize the facilities and thus cause the 
cost to be incurred.”).

77 
and for transmission service.231  Protestors are correct that PJM’s proposed collateral 
requirements do not “bear[] any relation” to PJM’s current collateral requirements.232  The 
long-term, up to 15-year payment obligation to RBP Resources is unlike any other 
commitment in PJM.  As such, the credit requirement for the long-term RBP committed 
obligation should be different from the credit requirements for PJM’s capacity and energy 
markets and transmission services.   
Currently, PJM utilizes the Peak Market Activity metric to determine the 
appropriate credit requirement for each LSE buyer of transmission, capacity, energy, and 
ancillary services.  Generally, PJM requires LSEs to maintain credit based on the greatest 
amount invoiced on a rolling period of one, two, three, or four weeks.233  To be clear, Peak 
Market Activity is a backward-looking metric that is used to determine the amount of credit 
needed to protect PJM’s markets and Members from default of amounts owed for 
obligations delivered.   
Peak Market Activity’s rolling basis for the credit requirement makes sense for 
these products.  PJM’s capacity markets procure forward capacity commitments, and 
associated LSE buyer obligations, on a year-by-year basis.  But, PJM does not have any 
 
231 NOVEC Protest at 22; see EKPC Protest at 23 (“[T]he same obligation is also collateralized twice.  The 
RBP Charge is secured in advance by the Credit Rate, and once the Delivery Year begins and RBP Charges 
are billed, those same charges enter the LSE’s Peak Market Activity through the ordinary operation of 
[Tariff,] Attachment Q and are secured again.”). 
232 See EKPC Protest at 26. 
233 See Tariff, Attachment Q, section VII.A; see PJM Interconnection, L.L.C., 186 FERC ¶ 61,055, at P 3 
(2024) (“Peak Market Activity is one of the tools that PJM utilizes to determine a market participant's risk 
exposure and the level of financial security required to support that market participant’s activity in the PJM 
markets.  Under the Tariff, PJM must calculate the Peak Market Activity for each participant to determine 
how much credit or collateral the participant must provide to PJM to participate in the PJM markets.  Peak 
Market Activity is calculated based on invoices for the market participant’s transaction activity in all PJM 
Markets, excluding FTR Net Activity, Virtual Transactions Net Activity, and Export Transactions Net 
Activity.  To satisfy its Peak Market Activity credit requirement, each participant must maintain a sufficient 
unsecured credit allowance and/or collateral, as applicable.” (footnotes omitted)).

78 
rules specific to the credit risk associated with the LSE buyers’ obligation to pay capacity 
charges throughout the year; rather, such are captured in Peak Market Activity, and to the 
extent an LSE defaults on its obligations, the provider of last resort for that load becomes 
responsible on a going-forward basis.   
In contrast, PJM envisions that an LSE’s obligation to pay RBP Charges should not 
be shunted to a provider of last resort—the idea is that the large load driving the need for 
the RBP should bear these costs—through its LSE, consistent with the Ratepayer 
Protection Pledge.  Once assigned cost responsibility, an LSE should assume that it will be 
responsible for paying RBP Charges through the remainder of the term, i.e., through the 
end of the 2042/2043 Delivery Year.234  Thus, the RBP cost allocation and credit 
requirements are fundamentally different from PJM’s existing capacity payment 
obligations, and comparisons to Peak Market Activity, and its rolling-based credit 
requirement, are accordingly misplaced.235 
In sum, Peak Market Activity and the proposed RBP credit requirement serve two 
different purposes and track different types of financial exposure.  The core difference is 
what they measure.  Peak Market Activity manages immediate, rolling operational risk 
from daily transactions based upon a rolling, backward-looking billing history.  In contrast, 
the proposed RBP credit requirement is to cover forward-looking risk over a long-term, up 
 
234 There appears to be some confusion about when the collateral requirements would need to be posted and 
how much would need to be posted for a given Delivery Year.  See Constellation Protest at 16.  PJM therefore 
clarifies that an LSE-allocated responsibility for paying RBP Charges does not need post collateral until 45 
days “[p]rior to the first Delivery Year” it is responsible for paying RBP Charges.  See July 31 Filing, 
proposed Tariff, Attachment DD, section 18.8(b).  And, the amount of collateral required would be based on 
the RBP UCAP MW committed for that Delivery Year.  Id., proposed Tariff, Attachment DD, 
section 18.8(b)(i)(A) (“The cumulative RBP credit requirement for Load Serving Entities for a given 
Delivery Year shall be equivalent to the product of the RBP Credit Rate multiplied by RBP UCAP MW 
committed . . . . ”).  In other words, no collateral would be required for RBP Resources are not in service for 
that Delivery Year, and no RBP Charges would be assessed.  
235 See EKPC Protest at 26; id., Coscia Affidavit ¶¶ 25-29; Equinix Comments 14-16.

79 
to 15-year commitment to sellers.  Thus, it is clear that the RBP credit requirement is not 
“duplicative” of Peak Market Activity, as protestors claim.   
3. 
PJM’s proposed LSE credit requirement is properly tailored to 
cover long-term payment obligation and protect ratepayers from 
exposure to RBP Charges.   
A few protestors contend that PJM’s proposal LSE credit requirement is 
“unnecessary” and “excessive.”236  In variations on these themes, FirstEnergy argues that 
“PJM must be able to show that its proposed collateral requirements are reasonably tailored 
to the actual credit risk presented by specific LSEs, or substantially similar classes of 
LSEs;”237 EKPC argues that it was not “derived from measured exposure;”238 and NOVEC 
argues that “at the most, RBP buyers should only have to provide collateral for the 
incremental cost of the RBP clearing price above the weighted RPM clearing price for the 
relevant Delivery Year.”239  Each of these arguments misses the mark. 
a. 
The LSE RBP credit requirement is necessary to protect 
ratepayers. 
As an initial matter, PJM’s proposed credit requirement definitely is not 
“unnecessary.”  Without a properly designed credit requirement, other ratepayers (i.e., 
those not associated with the large loads causing the need for the RBP and the RBP 
Resources) would be exposed to paying for these resources.  To minimize other ratepayers’ 
exposure to RBP Charges, RBP Charge payment obligations must be properly 
 
236 NOVEC Protest at 19; FirstEnergy Comments and Protest at 7; Equinix Comments at 14. 
237 FirstEnergy Comments and Protest at 8. 
238 EKPC Protest at 23. 
239 NOVEC Protest at 22.

80 
collateralized such that all default risk rests with those allocated RBP cost responsibility.240  
As discussed, this should not be controversial.   
b. 
The LSE RBP credit requirement is objective, not unduly 
discriminatory, and just and reasonable. 
Contrary to FirstEnergy’s claims,241 PJM’s approach of treating each LSE-
allocated cost responsibility equally, in an open and transparent manner, is just and 
reasonable.  Ms. Gwen Kelly, PJM’s Senior Director, Credit Risk and Collateral 
Management, testified that “PJM considered that the relevant financial exposure is created 
by the portfolio of committed RBP resources rather than by any individual LSE in 
isolation.”242  PJM looked at the forward obligation to the RBP Resources instead of 
individual LSE’s creditworthiness and ability to pay for a couple of reasons.  One, this 
provided the best approach for protecting other ratepayers from exposure to RBP Charges.  
That is, by looking at the obligation and not the payor, PJM can better devise credit rules 
to safeguard the payment and reduce exposure in case of default.   
Two, this approach would allow for a uniform credit rate applicable to each 
allocated RBP UCAP MW.  As such, PJM has proposed an “objective, transparent, and 
 
240 See July 31 Filing, proposed Tariff, Attachment DD, section 18.9(a) (“In the event a Load Serving Entity 
defaults and fails to pay an RBP Charge, the defaulted amount will be allocated to all remaining Load Serving 
Entities responsible for paying RBP Charges based on their pro-rata share of the total RBP Charges for all 
such Load Serving Entities.  Such amounts may be offset by the RBP Collateral posted by the defaulting 
Load Serving Entity.”).  In the July 31 Filing, PJM inadvertently described how the allocation of LSE defaults 
on RBP Charges would be treated.  PJM correctly described the management of LSE defaults at Part III.F.5, 
explaining that “upon any LSE’s default of RBP Charges, the defaulted amounts shall be reallocated to among 
the other LSEs allocated RBP Charges based on their proportional share of the total RBP Charges assessed 
across the PJM Region.”  July 31 Filing, Transmittal Letter at 122 (citing id., proposed Tariff, Attachment 
DD, section 18.9(a)).  However, PJM misdescribed how the management of LSE defaults in Part III.C.10, 
and the Commission should ignore that redundant and incorrect discussion in the July 31 Filing. 
241 See FirstEnergy Comments and Protest at 8 (PJM’s proposal is unjust and unreasonable “because it 
automatically treats [LSEs] as presenting the same nonpayment risk as LSEs without comparable cost 
recovery mechanisms.”). 
242 July 31 Filing, Affidavit of Gwen Kelly on Behalf of PJM Interconnection, L.L.C. (Attachment D) ¶ 21 
(“Kelly Aff.”).

81 
consistent means of allocating the aggregate collateral requirement among the LSEs 
responsible for the underlying payment obligations.”243  A uniform approach ensures 
non-discriminatory credit requirements for all LSEs allocated cost responsibility, and each 
LSE-allocated cost responsibility for RBP Charges is required to post collateral 
proportional to its allocated share of the RBP portfolio.  To implement this approach, “PJM 
developed a methodology that first determines the aggregate collateral necessary to address 
the payment exposure associated with the portfolio of committed RBP Resources and then 
allocates that collateral requirement among the LSEs responsible for payment of RBP 
Charges.”244   
Three, PJM’s approach is just and reasonable when considering the alternative.  
Evaluating the creditworthiness of each LSE serving these new large loads over a 
commitment period of up to 15 years would not provide the same level of assurance of 
payment of RBP Charges over the entire period.  That is, today’s assessment that one LSE 
is financially strong may not tell PJM much about its ability to continue to pay RBP 
Charges many years from now.  In addition, such an approach would fail to ensure 
sufficient credit to cover RBP Charges in the event the LSE goes out of business during 
the payment term.  Indeed, the credit quality of an LSE can change considerably during a 
15-year term.  A company with investment-grade credit may suffer financial set backs 
during the period, and have worsening credit as a result.  S&P Global, a credit rating agency 
and financial data and research company, tracks the probability of a credit rating 
transitioning from one rating to another over a specific timeframe.  For present purposes, 
 
243 Id. ¶ 23. 
244 Id. ¶ 22.

82 
PJM extrapolated S&P Global’s 10-year credit mitigation table245 to reflect a 15-year 
period.  The results are shown in Table 2 below.  
Table 2: 15-year Credit Migration Table 
15 Year 
(no-NR) 
normalized AAA 
AA 
A 
BBB 
BB 
B 
CCC/C D 
AAA 
23.1% 44.8% 22.3% 6.3% 
0.9% 
0.6% 
0.1% 
2.0% 
AA 
1.8% 
31.8% 44.6% 15.2% 2.6% 
1.1% 
0.1% 
2.8% 
A 
0.3% 
7.5% 
49.9% 29.7% 5.4% 
2.1% 
0.3% 
4.8% 
BBB 
0.1% 
1.8% 
20.7% 50.2% 11.1% 4.7% 
0.4% 
11.0% 
BB 
0.0% 
0.4% 
4.9% 
22.2% 21.4% 12.9% 1.2% 
36.9% 
B 
0.0% 
0.1% 
1.2% 
6.1% 
11.0% 12.1% 1.2% 
68.2% 
CCC/C 
0.0% 
0.0% 
0.4% 
1.7% 
3.0% 
2.6% 
0.3% 
92.0% 
D 
0.0% 
0.0% 
0.0% 
0.0% 
0.0% 
0.0% 
0.0% 
100.0% 
 
As can be seen, PJM estimates an 11% likelihood that an entity with investment-grade 
credit rating of BBB could transition to default status (D rating), while an entity with a BB 
rating would have a 36.9% likelihood.  In the scenario where an alternative, 
specific-LSE-driven credit approach is used in place of PJM’s proposed obligation-focused 
approach, such declining creditworthiness would require PJM to request more and more 
collateral from such entities in order to compensate for the increasing default risk.  As a 
matter of practice, PJM seeks to avoid scenarios where it is exposed to declining 
counterparty credit quality.  Given the foregoing, PJM’s proposed methodology is just and 
reasonable, as it is based on the committed obligation itself and avoids having the adequacy 
of the credit protection depend upon long-range predictions about individual LSE’s 
financials. 
 
245 See Default, Transition, and Recovery: 2025 Annual U.S. Corporate Default And Rating Transition Study, 
S&P Global Inc. (June 12, 2026), https://www.spglobal.com/ratings/en/regulatory/article/default-transition-
and-recovery-2025-annual-us-corporate-default-and-rating-transition-study-s101688003 
[https://perma.cc/7LTL-J8SQ].

83 
c. 
Consistent with the Commission’s credit policy, the 
Proposed LSE RBP credit requirement is properly tailored 
to protect other ratepayers from RBP Charges. 
Contrary to EKPC’s and NOVEC’s arguments,246 PJM’s proposed credit 
requirement is not excessive but is in fact properly tailored to mitigate the risk associated 
with RBP commitments throughout the up to 15-year RBP commitment term and therefore 
is derived from the measured forward exposure of the RBP Charges.  As Ms. Kelly 
testified, “PJM evaluated the credit tools needed to mitigate potential defaults from 
non-payment of RBP Charges,” and “found that its current credit tools do not contemplate 
the long-term nature of RBP and the risk of future non-payment that results.”247  Indeed, 
PJM’s current credit tools—primarily, Peak Market Activity—are geared for recovery of 
obligations provided, i.e., for energy and capacity that was provided, and are not designed 
to project for future obligations.   
Accordingly, “PJM evaluated methodologies for determining the amount of 
collateral required from LSEs.”248  PJM determined that “a methodology that first 
determines the aggregate collateral necessary to address the payment exposure associated 
with the portfolio of committed RBP Resources and then allocates that collateral 
requirement among the LSEs responsible for payment of RBP Charges”249 would 
effectively obtain sufficient collateral to protect other ratepayers from shouldering the 
burden of the RBP Resources procured to address the capacity needs of the large loads 
driving the current shortfall.   
 
246 See NOVEC Protest at 19-24; EKPC Protest at 21-23. 
247 July 31 Filing, Kelly Aff. ¶ 19. 
248 Id. ¶ 21. 
249 Id. ¶ 22.

84 
PJM’s proposal is consistent with the Commission’s credit policy, which requires 
“a reasonable balance between protecting PJM’s markets and its members against the risk 
of default and ensuring that market participants have adequate flexibility to manage their 
collateral requirements.”250  This balance must recognize that “as more credit risk is 
tolerated, PJM is more likely to experience collateral shortfalls and, in turn, defaults,”251 
which are borne by PJM Members.252  On the other hand, the Commission has cautioned 
that “overly conservative collateral requirements or collateral requirements that are poorly 
correlated to credit risk can impose costs that undermine a well-functioning, efficient 
market by reducing liquidity and creating barriers to market participation.”253  This analysis 
should also consider the relative risk level of such participation and the payment obligation 
being collateralized.  Thus, just and reasonable credit rules “correlate the . . . credit 
requirement with the credit risk.”254  As proposed, PJM’s approach balances the protection 
of Members against the effects of LSE default and appropriately correlating the credit 
requirement with credit risk by “establish[ing] an initial level of collateral that provides 
commensurate protection against non- payment while avoiding full collateralization of the 
entire 15-year contractual commitment.”255 
 
250 PJM Interconnection, 186 FERC ¶ 61,055 at P 27.   
251 Id. P 28 & n.63 (citing Credit Reforms in Organized Wholesale Electric Markets, Order No. 741, 133 
FERC ¶ 61,060, at P 2 (2010) (“[I]f more risk is tolerated and access to credit is too easy to obtain, then the 
market is more susceptible to defaults and customers bear the burden of the costs that flow from such 
defaults.”), order on reh’g, Order No. 741-A, 134 FERC ¶ 61,126, reh’g denied, Order No. 741-B, 135 FERC 
¶ 61,242 (2011)). 
252 See Operating Agreement, section 15.2.2. 
253 PJM Interconnection, 186 FERC ¶ 61,055 at P 28 (citing Order No. 741, 133 FERC ¶ 61,060 at P 2 (“[I]f 
more risk is tolerated and access to credit is too easy to obtain, then the market is more susceptible to defaults 
and customers bear the burden of the costs that flow from such defaults.”). 
254 Id. P 29. 
255 July 31 Filing, Kelly Aff. ¶ 24.

85 
d. 
Letters of credit and cash are appropriate forms of collateral.  
NOVEC complains that “PJM should permit NOVEC to satisfy all or a substantial 
portion of the requirement through unsecured credit or another demonstration of 
creditworthiness rather than requiring cash collateral or a letter of credit for the full notional 
amount,” implying that its “investment-grade credit rating, financial condition, and 
established record of satisfying its PJM obligations,” should afford it different treatment.256  
However, as discussed in the July 31 Filing, PJM purposefully chose to limit the forms of 
collateral to Letters of Credit and cash.257  PJM considered the unsecured credit available 
from existing Market Participants.  But, PJM’s experience—predominantly from hot and 
cold weather events—has shown that, generally speaking, Market Participants used their 
full amount of unsecured credit to cover their Peak Market Activity credit obligations 
associated with those periods.  Further, as discussed above, there is a likelihood that even 
entities with investment grade credit may see their financial condition deteriorate over 15 
years.  In such event, the entity’s access to access to liquidity may also evaporate, making 
it functionally unable to post additional collateral precisely when default risk rises.  To 
insulate against this downward spiral, the exclusion of unsecured credit and requirement 
for upfront collateral is prudent risk management.  As such, PJM determined that, as a 
general rule, there would not be sufficient unsecured credit available from these LSEs to 
cover the up-to 15-year forward credit obligation. 
 
256 NOVEC Protest at 24. 
257 See July 31 Filing, Transmittal Letter at 109-10.

86 
4. 
Given that the Peak Market Activity is not duplicative of the LSE 
RBP credit requirement, claims that the RBP Credit Rate should be 
reduced because RBP Charges are contracts for differences lack 
merit. 
EKPC and NOVEC argue that the credit requirement should be reduced to reflect 
the fact that the RBP Charges will be only for the difference between [the MW-weighted 
average of the levelized procurement cost of all selected RBP Sell Offers] and [the 
weighted average RPM clearing price for the Delivery Year] and not just for the weighted 
RBP price.  These arguments miss the mark.  At root, these claims are based on the false 
premise that the RBP credit requirement is duplicative of PJM’s Peak Market Activity, and 
therefore there would be no need to secure collateral for the full-forward payment 
obligation.258   
However, as demonstrated above, the backward-looking Peak Market Activity 
approach is not adequate for collateralizing the up to 15-year forward obligation presented 
by RBP Charges.259  Given that the RBP is to address the capacity shortfall from the 
2027/2028 and 2028/2029 RPM Auctions, which is primarily driven by the unprecedented 
addition of large loads (in the form of Load Adjustments), the loads causing the RBP—
through their LSEs—should bear the costs of the RBP Resources throughout the full term.  
They will pay for their RPM capacity payments, as part of the pool of capacity 
commitments, plus the RBP Charges based on the contract for differences.  That is, for 
each Delivery Year, these LSEs will pay the full MW-weighted average of the levelized 
 
258 See, e.g., EKPC Protest at 25; NOVEC Protest at 21-22. 
259 To clarify that Peak Market Activity is not an adequate credit tool for RBP Charges, PJM consents to 
revising July 31 Filing’s proposed Tariff, Attachment DD, section 18.8 to remove the sentence:  “In addition, 
settlement during any Delivery Year of cleared positions resulting from, or expected to result from, the 
Reliability Backstop Procurement may be included, as appropriate, in Peak Market Activity pursuant to 
Tariff, Attachment Q, Section VII.A.”  PJM recognizes that this sentence could cause confusion that RBP 
Charges may be captured in the Peak Market Activity credit tool, and therefore its omission from the accepted 
language would facilitate proper understanding of the RBP Credit rules.

87 
procurement cost of all selected RBP Sell Offers for the RBP Resources and not just the 
contract for differences amount.  Because the Peak Market Activity does not prospectively 
collateralize the RPM component over the up to 15-year term, PJM requires a separate 
credit tool to cover the forward RPM obligation and the forward RBP Charge obligation.  
The sum of these obligations will be known after the RBP closes (i.e., the weighted RBP 
price) and can be straightforwardly used to determine the credit requirement.  Conversely, 
considering only the contract for differences amount—which are unknown and 
unknowable for each of the up to 15 Delivery Years—would needlessly over-complicate 
the exercise without any concomitant benefits because these LSEs must pay the full amount 
regardless.  And, as a result, those LSEs should be required to post collateral sufficient to 
shield other ratepayers from their default risk, without the credit requirement being too 
high.   
PJM’s proposal accomplishes this objective.  As Ms. Kelly testified, “PJM 
concluded that an initial credit rate of $1.5 million per committed RBP MW would 
collateralize approximately 50% of the estimated contractual value associated with the 
commitment.”260  PJM’s proposal allows for the credit rate to decrease “when changes in 
the underlying RBP commitment portfolio demonstrate that previously required collateral 
exceeds the remaining expected payment exposure.”261   
 
260 July 31 Filing, Kelly Aff. ¶ 26 (emphasis added). 
261 Id. ¶ 30; see id., proposed Tariff, Attachment DD, section 18.8(b)(i)(A) (“[T]he RBP Credit Rate shall 
equal $1.5 million, as may be reduced, for reasons including a change in the total committed RBP UCAP 
MW, when total posted RBP Collateral is greater than the total remaining RBP Charges obligations, over 
time by the Office of the Interconnection to an amount sufficient to cover the total existing RBP Charges 
obligations . . . .”).

88 
Several entities raised questions as to whether an initial RBP Credit Rate of 
$1.5 million per RBP UCAP MW is the best value.262  PJM has demonstrated that this 
value is just and reasonable and supported by substantial evidence.263  This value is keyed 
to a potential outcome of the RBP, the maximum MW-weighted average of the levelized 
procurement cost of all selected RBP Sell Offers of $555/MW-day, and represents about 
50% of the notational contract value at that price.264  These are more than reasonable 
assumptions to properly protect other ratepayers from RBP Charges.  Indeed, the 50% of 
the notational contract value serves the same balancing principle articulated in the 
Commission’s credit policy.  It represents approximately 50% of a quantifiable potential 
contractual exposure, rather than full collateralization, and can decline as the remaining 
exposure declines. This calibration undermines claims that the amount is excessive or 
insufficiently correlated to credit risk.  Plus, should the weighted average clearing price be 
lower than the $555/MW-day, PJM likely would be able to return collateral earlier.   
5. 
LSEs contracting with new large loads are requiring collateral that 
can be used to meet PJM’s LSE RBP credit requirement.  
Some protestors asserted that the proposed initial RBP Credit Rate of $1.5 million 
per MW would affect their business,265 but such claims ignore the fact that standard 
business practices for LSEs signing up new large loads include requiring collateral.   
NOVEC argues that PJM’s proposed LSE credit requirement would “disrupt 
NOVEC’s ordinary business operations,” and that “[t]he Commission should not approve 
 
262 See, e.g., NOVEC Protest at 19-24; FirstEnergy Comments and Protest at 9. 
263 See July 31 Filing, Transmittal Letter at 114-22; see id., Kelly Aff. ¶¶ 24-33; see also, e.g., Papago Tribal 
Util. Auth. v. FERC, 723 F.2d 950, 957 (D.C. Cir. 1983) (finding that the Commission’s rate “was just and 
reasonable [and] did not amount to a finding that every other rate of return was not”). 
264 See July 31 Filing, Kelly Aff. ¶¶ 25-28. 
265 See, e.g., NOVEC Protest at 20.

89 
a collateral requirement that is an impossibility, a hindrance to an entity’s ability to operate, 
and an injustice.”266  NOVEC states that based on its ~19% share of the RBP Target 
amount, i.e., ~19% of the new large loads that caused the current shortfall,267 and PJM’s 
proposed credit rate, NOVEC’s collateral would be about $1.95 billion.  NOVEC 
complains that this would be “an extraordinary imposition.”268   
The Commission should look at NOVEC’s concerns in context.  The entire PJM 
Region is facing a capacity shortfall because entities like NOVEC contracted to serve new 
large loads on an unprecedented scale at an extremely rapid pace—without requiring any 
associated new capacity.  Indeed, according to NOVEC’s Load Adjustment presentation at 
PJM’s September 16, 2025 Load Analysis Subcommittee, NOVEC’s actual load grew from 
about 1,204 MW in 2019 to 2,368 MW in 2025, with data centers comprising all or nearly 
all of that growth.269  NOVEC’s own near-term forecast shows that it planned to add over 
40 new data centers to its load between 2026 to 2028, increasing its contracted capacity 
from ~3,000 MW in 2025 to ~6,350 MW in 2028.270   
As for NOVEC’s collateral requirement, the underlying idea is that the large loads 
it serves should bear these costs.271  Of course, the Commission and PJM cannot dictate 
 
266 NOVEC Protest at 20. 
267 See July 31 Filing, Croop Aff. ¶ 46. 
268 NOVEC Protest at 20. 
269 PJM Load Analysis Subcommittee, NOVEC Data Center Load Forecast, Northern Virginia Electric 
Cooperative, 
4 
(Sep. 
16, 
2025), 
https://www.pjm.com/-/media/DotCom/committees-
groups/subcommittees/las/2025/20250916/20250916-item-04b---novec-large-load-request.pdf 
[https://perma.cc/ZJD5-36Y6] (“NOVEC Data Center Load Forecast”). 
270 NOVEC Data Center Load Forecast at 15.  
271 FirstEnergy alleges that the collateral costs “will ultimately be borne by retail ratepayers” and “harm retail 
customers.”  FirstEnergy Comments and Protest at 8-9.  PJM believes that the large loads driving the Load 
Adjustment should be allocated any costs of posting the necessary collateral, not other ratepayers.  The 
allocation of such costs among an LSE’s ratepayers is a matter within the state’s jurisdiction.

90 
the terms of the retail tariffs to require NOVEC to pass these costs to its large loads,272 and 
PJM does not seek to do so here.  NOVEC has testified before the Virginia State 
Corporation Commission that its contracting practices with large loads include “strict credit 
review and collateral requirements” and “NOVEC has been very successful at putting 
credit protection instruments in place that offer a variety of solutions available to different 
types of data center customers.”273  Presumably, the collateral posted by NOVEC’s data 
center customers could be used to meet the RBP credit requirements.274 
More broadly, the Credit Support Annex of the International Swaps and Derivatives 
Association (“ISDA”) Master Agreement supports the notion that these LSEs serving large 
loads should have required collateral from their customers that could be contributed toward 
meeting the RBP collateral requirement.  To the extent the LSE relied on the ISDA Master 
Agreement, paragraph 6(c)(i) of the Credit Support Annex allows the LSE to use the large 
load’s collateral toward meeting the LSE’s collateral requirements.275 
Further, other LSEs in the PJM Region are imposing strong collateral requirements 
in their contracts serving large loads.  Generally, it appears that utilities are designing the 
 
272 See Tri-State Generation & Transmission Ass’n, 193 FERC ¶ 61,070, at P 52 (2025). 
273 Ex Parte: Electric Utilities and Load Growth, Case No. PUR-2024-00144, Opening Remarks of Gilbert 
D. Jaramillo on Behalf of Northern Virginia Electric Cooperative, at 4 (Va. S.C.C. Dec. 16, 2024), 
https://www.scc.virginia.gov/docketsearch/DOCS/82vs01!.PDF [https://perma.cc/2ZRP-3UYA]. 
274 Regardless, NOVEC would not be without options.  For example, as NOVEC is rate regulated by the 
Virginia State Corporation Commission, NOVEC could, subject to applicable law, seek to securitize the costs 
of its RBP collateral requirement (in the form of low-interest, ratepayer-backed bonds sold to investors) and 
then recover such costs through a Virginia State Corporation Commission-approved non-bypassable charge.   
275 Int’l Swaps & Derivatives Ass’n, 2016 ISDA Credit Support Annex (Bilateral Form; New York Law) 
¶ 6(c) (“Use of Posted Collateral.  Unless otherwise specified in Paragraph 13 and without limiting the rights 
and obligations of the parties under Paragraphs 3, 4(d)(ii), 5, 6(d) and 8, if the Secured Party is not a 
Defaulting Party or an Affected Party with respect to a Specified Condition and no Early Termination Date 
has occurred or been designated as the result of an Event of Default or Specified Condition with respect to 
the Secured Party, then the Secured Party will, notwithstanding Section 9-207 of the New York Uniform 
Commercial Code, have the right to (i) sell, pledge, rehypothecate, assign, invest, use, commingle or 
otherwise dispose of, or otherwise use in its business any Posted Collateral it holds, free from any claim or 
right of any nature whatsoever of the Pledgor, including any equity or right of redemption by the Pledgor.”).

91 
level of collateral to cover the utility’s exposure if the data center does not perform as 
contemplated—which is the same logic underlying PJM’s credit requirement. 
For example, Ohio Power Company (operating as AEP Ohio) Schedule DCT (Data 
Center Tariff) requires that data centers that do not meet certain creditworthiness standards 
must provide collateral at contract signing equal to 50% of their total minimum charges for 
the full contract term.276  AEP Ohio also requires the customer to reimburse 100% of 
buildout costs if it cancels or delays a project by more than 12 months before the target 
energization date.  These are the types of costs that would be contemplated when deriving 
a credit requirement. 
For Dominion, the Virginia State Corporation Commission approved a new Rate 
Schedule GS-5, effective January 1, 2027, for loads 25 MW or greater and a load factor of 
at least 75%.  Rate Schedule GS-5 requires such loads to contract with Dominion for at 
least 14 years and allow for early termination exit fees covering any outstanding minimum 
charges over the remaining contract duration.  With respect to collateral requirements, the 
Virginia State Corporation Commission approved Dominion’s proposed terms, “including: 
(1) $1.5 million/MW; (2) a reduction up to 70% based on the customer’s established credit; 
(3) provisions for third-party guarantees and letters of credit; and (4) releasing 1/14th of 
the collateral requirement each year throughout the contract.”277  As Dominion has 
described, the collateral must be provided before the large load is energized.278  
 
276 See Ohio Power Company, P.U.C.O. No. 21, Schedule DCT, Original Sheet No. 223-5. 
277 Application of Virginia Electric and Power Company, For a 2025 biennial review of the rates, terms, and 
conditions for the provision of generation, distribution and transmission services pursuant to § 56-585.1 A 
of the Code of Virginia, Case No. PUR-2025-00058, Final Order, at 25 (Va. S.C.C. Nov. 25, 2025), 
https://www.scc.virginia.gov/docketsearch/DOCS/89g601!.PDF. 
278 Meeting the Demands for Large-Load Customers with Reliable, Affordable, and Increasingly Clean 
Energy, 
Dominion 
Energy, 
5 
(May 
2026), 
https://sustainability.dominionenergy.com/GS-
5%20Large%20Load%20Rate%20Class%20Report.pdf 
[https://perma.cc/3RZD-C3M4] 
(“Collateral

92 
Similarly, the Pennsylvania Public Utility Commission has approved PPL’s Rate 
Schedule LP-6 for large loads (50 MW or greater) that commenced service on or after 
October 1, 2025.279  PPL’s Rate Schedule LP-6 calls for a minimum contract term of 10 
years and “security in an amount equal to the cost of upgrades needed to serve the customer, 
including, but not limited to, the costs that the Company would not have incurred but for 
the interconnection of the customer.”280  Rate Schedule LP-6 provides that in the event the 
large load defaults PPL “shall draw on the security instrument in the amount of the 
outstanding revenue guarantee.”281 
As can be seen, LSEs are imposing collateral requirements needed to cover the 
costs to serve the large loads—again, similar to PJM’s LSE RBP credit requirement to 
cover the costs of the capacity needed to serve these new large loads. 
6. 
While PJM has proposed a just and reasonable LSE credit 
requirement and urges Commission acceptance of it, PJM 
recognizes that there is time to investigate further and consents to 
modification if the Commission desires. 
PJM has proposed a just and reasonable approach to determining the proper 
buyer-side LSE RBP credit requirement.  Nonetheless, PJM understands that reasonable 
minds may differ as to how to set the initial RPM Credit Rate.  Some have suggested that 
the credit rate should be keyed to the actual MW-weighted average of the levelized 
procurement cost of all selected RBP Sell Offers that results from the RBP and not the 
 
requirements, which were approved to become more stringent pursuant to a recent Commission ruling, are 
due to be paid before the customer’s meter is set and its project is energized.”). 
279 PPL Electric Utilities Corporation Rate Schedule LP-6 Large Load Interconnections, Supplement No. 2 
to Electric Pa. P.U.C. No. 202, First Revised Page No. 35C (effective July 1, 2026), 
https://www.pplelectric.com/site/-/media/PPLElectric/At-Your-Service/Docs/Current-Electric-
Tariff/2026/July/Rate-Schedule-LP-6-Large-Load-Interconnections.pdf (“PPL Rate Schedule LP-6”). 
280 Id.   
281 Id.

93 
maximum of such value.282  PJM consents to such an approach, because it maintains a 
credit requirement corresponding to the level of risk necessary to insulate other 
ratepayers283 and would implement such a change on compliance if the Commission 
directs.284   
Further, although PJM has proposed a just and reasonable approach to determining 
the proper buyer-side LSE RBP credit requirement, PJM recognizes that reasonable minds 
may differ on the credit approach.  Given that an LSE’s collateral is not required to be 
posted until the first Delivery Year for which RBP Resources will be in service and 
providing capacity, i.e., the 2028/2029 Delivery Year,285 the LSE credit rules do not need 
to be effective for the RBP to be conducted.  To be clear, the RBP Seller credit rules in 
proposed Tariff, Attachment DD, section 18.8(a) do need to be effective to conduct the 
RBP.  Accordingly, consistent with the consent PJM provided in the July 31 Filing to the 
Commission’s exercise of authority to modify and/or sever the proposed Tariff and RAA 
language, as needed and permitted under the FPA and NRG Power Marketing,286 PJM 
would consent to the Commission resolving the applicable buyer-side LSE RBP Credit 
Rate through additional procedures.   
 
282 See NOVEC Protest at 22. 
283 See July 31 Filing, Transmittal Letter at 3-4, 130-33. 
284 For this reason, PJM does not consent to the rolling forward exposure-based credit requirement suggested 
by Equinix Inc.  See Equinix Comments at 16. 
285 See July 31 Filing, proposed Tariff, Attachment DD, section 18.8(b). 
286 NRG Power Mktg., LLC, 862 F.3d 108 (D.C. Cir. 2017).  As the Commission has repeatedly stated, “[t]he 
United States Court of Appeals for the District of Columbia Circuit has held that, in certain circumstances, 
the Commission has ‘authority to propose modifications to a utility’s [FPA section 205] proposal if the utility 
consents to the modifications.’”  N.Y. Indep. Sys. Operator, 188 FERC ¶ 61,051, at P 22 n.36 (2024) (second 
alteration in original) (citing NRG Power Mktg., 862 F.3d at 114-15); see Midcontinent Indep. Sys. Operator, 
Inc., 180 FERC ¶ 61,141, at P 26 n.29 (2022) (same), order on reh’g, 182 FERC ¶ 61,096 (2023); ISO New 
Eng., Inc., 175 FERC ¶ 61,172, at P 16 n.20 (2021) (same).

94 
K. 
The Proposed Transmission Owner Exit Requirements Are Necessary to 
Ensure Price Certainty for RBP Resources Over the 15-year Commitment 
Period, Thereby Encouraging Participation in the RBP. 
In the event that a Transmission Owner elects to exit PJM during or prior to the 
2042/2043 Delivery Year, PJM proposed Tariff provisions in Attachment DD, section 18.7 
places such a Transmission Owner on notice of their responsibility to avoid undermining 
the cost certainty of the 15-year RBP Resource commitment, which aids the financing of 
RBP Resources that can be placed in service quickly, as it would avoid creating stranded 
costs related to RBP Resources and the loads served by such resources as a result of a 
Transmission Owner’s decision to leave PJM.   
At bottom, the proposed Tariff provisions balance the dual interests of providing 
adequate notice to Transmission Owners and retaining flexibility in recognition that, 
should a Transmission Owner elect to exit PJM at some point in the future.  Furthermore, 
the proposed Tariff provisions help to protect residential customers and other consumers 
remaining in the PJM Region from being held responsible for stranded RBP costs arising 
from a Transmission Owners’ decision to leave PJM, in keeping with the Ratepayer 
Protection Pledge, which a significant number of PJM’s Transmission Owners are 
signatories to.287 
 
287 The PJM Transmission Owners that are signatories to the Ratepayer Protection Pledge and have filed 
comments and protests in this docket include: AES Corporation, EKPC, Dominion, FirstEnergy, and PPL.  
See White House Ratepayer Protection Pledge Signatories.

95 
1. 
The proposed Tariff language is sufficiently clear to put 
Transmission Owners on notice of their responsibilities with respect 
to RBP Resources in the event that they choose to exit from PJM.   
Several intervenors raise concerns that the proposed Tariff language implementing 
the Transmission Owner exit process lacks sufficient clarity and specificity.288  AEP claims 
that (1) the “standard” applied to the agreement into which Transmission Owners and RBP 
Resources in the zone may enter into in proposed Tariff, Attachment DD, section 18.7(a) 
is unclear; (2) PJM has not explained how it may “elect” to retain RBP Resources that can 
be pseudo-tied into PJM; and (3) it is unclear what sort of contractual arrangement in 
proposed Tariff, Attachment DD, section 18.7(b) a Transmission Owner should enter into 
with RBP Resources outside of the zone.289  PPL asserts that PJM’s proposed language 
violates the FPA’s requirement to provide clear and specific rates and charges, particularly 
with respect to the costs that would be at issue if a resource is pseudo-tied or in the event 
of a Transmission Owner’s exit, as well as with respect to who would be responsible for 
making a filing with the Commission.290  Similarly, AEP argues that exit terms should be 
able to be determined prior to a Transmission Owner withdrawing from PJM.291   
None of these arguments render PJM’s proposed Tariff revisions unjust and 
unreasonable.  As discussed below, there is sufficient detail provided in these revisions to 
put Transmission Owners on notice of their responsibilities in a manner that also provides 
for flexibility to meet those obligations, particularly in light of the complexity and 
unknowns involved in a future, hypothetical withdrawal.   
 
288 See, e.g., AEP Limited Protest at 12-13; PPL Limited Protest and Request for Clarification at 10-12; EKPC 
Limited Answer at 5-6.   
289 AEP Limited Protest at 12-13. 
290 PPL Limited  Protest and Request for Clarification at 10-12. 
291 AEP Limited Protest at 17-20.

96 
Importantly, in the event a Transmission Owner does exit, there will be extensive 
negotiations that take place, not only with respect to RBP, but also a variety of other 
obligations.  Therefore, PJM drafted these sections with the intent of providing flexibility 
to the Transmission Owner and RBP Resource to develop the specific “rates, terms, and 
conditions” to effectuate the obligation to “preserve RBP commitments.”   
Critically, however, this flexibility is counterbalanced against the detailed Tariff 
provisions set forth in proposed Tariff, Attachment DD, section 18, which specifies the 
necessary terms and conditions for implementing the RBP.  Regarding AEP’s arguments 
about entering into agreements with RBP Resources, the proposed Tariff language in 
Attachment DD, sections 18.7(a) and 18.7(b) is sufficiently clear, particularly when read 
in the context of all of the proposed Tariff language.  In both proposed sections, it is clear 
that the purpose of such agreements is to ensure that both the exiting Transmission Owner 
“preserves the RBP commitments with the owners of”292 RBP Resources.  This, of course, 
is the entire purpose of this filing—to ensure that PJM has sufficient resources to maintain 
reliability throughout the 15-year commitment period.   
When reviewing proposed tariff language, the Commission must interpret tariff 
provisions “as part of an integrated whole.”293  Applying this principle here necessarily 
leads to the conclusion that such “rates, terms, and conditions” might include the issues 
addressed in proposed Tariff, Attachment DD, section 18 that would “preserve RBP 
 
292 July 31 Filing, proposed Tariff, Attachment DD, section 18.7(a) (emphasis added). 
293 Derby Fuel Cell, LLC, 194 FERC ¶  61,147, at P 22 & n.46 (2026) (citing Columbia Gas Transmission 
Corp., 27 FERC ¶ 61,089, at 61,166 (1984) (“In construing what a tariff means, certain general principles 
apply.  One looks first to the four corners of the entire tariff, considers the entire instrument as a whole, 
giving effect so far as possible to every word, clause and sentence, and attributes to the words used the 
meaning which is generally used, understood, and accepted.”)).

97 
commitments.”  At the same time, as discussed above, PJM intends to preserve flexibility 
for exiting Transmission Owners and RBP Resources as they negotiate any agreement. 
With respect to concerns that PJM may “elect” to retain an RBP Resource as a 
Capacity Resource, PJM notes that it must retain the discretion necessary to ensure how 
best to meet PJM’s resource adequacy and reliability needs—e.g., whether it makes sense 
for PJM to keep that RBP Resource after considering the topology of the transmission 
system at the time of the desired exit.  As Ms. Croop discusses in her affidavit, submitted 
with the July 31 Filing, for example, PJM does not project and calculate certain parameters 
15 years out.294  Further, PJM’s ongoing RTEP transmission planning processes will 
continue to assess the transmission system at any given time to account for changes to 
ensure ongoing deliverability of capacity resources.295  For example, it may be the case 
that, at the time the decision to exit has been made, PJM no longer needs that particular 
RBP Resource to be retained to meet reliability needs.  This discretion is also part and 
parcel of ensuring just and reasonable rates, as discussed in the NEDC/PJM Governors’ 
Principles which state, among other things, that PJM should “prevent consumers from 
bearing excessive ongoing costs.”296 
With respect to PPL’s arguments regarding pseudo-tie costs,297 PJM’s proposed 
Tariff language is more than sufficiently specific and clear regarding the costs at issue.  
Proposed Tariff, Attachment DD, section 18.7(a) states that the costs to be paid by the 
exiting Transmission Owner would include those needed to ensure “that such resource 
 
294 July 31 Filing, Croop Aff. ¶ 8. 
295 Id. ¶ 9. 
296 NEDC/PJM Governors’ Principles at 1; see 2026 PJM CIFP Proposal at 1. 
297 PPL Limited Protest and Request for Clarification at 11.

98 
meets the external Capacity Resource eligibility requirements set forth in Tariff, 
Attachment DD, section 5.5A prior to the Transmission Owner exiting PJM 
Interconnection, L.L.C.”  Again, the overall intent of this proposal is to ensure that PJM 
has sufficient capacity to meet reliability needs.  Should a Transmission Owner decide, in 
the future, to exit PJM, and if that Transmission Owner has incurred RBP responsibilities, 
that Transmission Owner must ensure that it continues to satisfy those responsibilities.  One 
option that the Transmission Owner may choose is to have the RBP Resource pseudo-tie 
back into PJM in the event the exiting Transmission Owner leaves with an RBP Resource.  
If such RBP Resource will be pseudo-tied, PJM’s proposed Tariff language and existing 
language in Attachment DD are clear as to what that would entail. 
With respect to arguments concerning the requisite Commission filing and costs 
associated with a Transmission Owner exiting PJM with net load, PJM again notes that 
such costs are appropriately decided at the time of Transmission Owner’s exit and subject 
to Commission approval.  It is impossible to determine, at this point in time, what exactly 
those circumstances may be.  The proposed Tariff language simply puts parties on notice 
that final cost determinations will be approved by the Commission.   
Similarly, the proposed Tariff provisions do not specify who may make such filing, 
as, again, it is impossible to determine, at this time, the scope of any Transmission Owner’s 
exit proceeding that may take place.  The proposed Tariff provides appropriate flexibility 
in this regard while also providing sufficient notice of the nature of the costs, namely those 
associated with ensuring RBP Resources commitments are appropriately honored.

99 
AEP and EKPC argue that exit terms should be specified up front and consistent 
with cost causation, adding that the lack of locational requirements298 underpins the 
uncertainty as to cost responsibility.299  For the reasons discussed above in this subsection, 
PJM’s proposed Tariff revisions are just and reasonable because, among other things, they 
specifically set out the obligations associated with RBP Resources, so there can be no 
question as to the types of responsibilities an exiting Transmission Owner may need to 
consider prior to exiting PJM.   
Further, AEP’s arguments fail to appreciate the numerous options provided to an 
exiting Transmission Owner regarding how it may choose to honor its RBP responsibilities, 
which greatly mitigates against the argued uncertainty.  For example, a Transmission 
Owner exiting with committed RBP Resources in its zone may (1) negotiate an agreement 
with the RBP Resource owners, free to advocate for whatever costs they deem appropriate 
to preserve the RBP Resource commitments; (2) attempt to pseudo-tie the RBP Resource 
into PJM, paying associated costs consistent with proposed Tariff, Attachment DD, 
section 18.7(a); or (3) pay for the costs associated with the remainder of the RBP 
Resource’s term as approved by the Commission.300  If a Transmission Owner exits with 
net load, it has similar options: (1) negotiate an agreement with the RBP Resources; or 
(2) pay all forward obligations as approved by the Commission.301  In short, the proposed 
Tariff, when read as a whole, provides sufficient notice regarding the nature of 
 
298 Responses to locational arguments are set forth in this Answer, see supra Part I.C.3. 
299 AEP Limited Protest at 17-18; EKPC Limited Answer at 4. Similar arguments regarding certainty 
necessary for Transmission Owners to make informed decisions about whether to exit PJM, and whether 
alleged uncertainty constrains such future decision-making, are raised by PPL and FirstEnergy and are 
addressed by the responses provided in this section.  See PPL Limited  Protest and Request for Clarification 
at 9-10; FirstEnergy Comments and Protest at 5. 
300 See July 31 Filing, proposed Tariff, Attachment DD, section 18.7(a).   
301 See id., section 18.7(b).

100 
responsibilities and the flexibility to meet them based on their own informed business 
decision-making. 
2. 
The proposed Tariff language in section 18.7(b) requiring an exiting 
Transmission Owner to pay “all forward obligations” is needed to 
ensure that RBP Resources have financial certainty and that loads 
remaining in PJM are not forced to bear excessive costs. 
AEP asserts that PJM’s proposed Transmission Owner exit provisions pertaining 
to net load exiting PJM in section 18.7(b) are unjust and unreasonable because they do not 
appear to incorporate the effect of offsetting credits that load remaining in PJM will benefit 
from.302  Similarly, AEP further argues that exiting Transmission Owners may be forced 
to bear excessive costs should RPM clearing levels decline as a result of its exiting load—
load remaining in PJM would see the benefit of this through RBP credits, while the exiting 
load would continue to pay for “surplus” capacity.303   
But, as PJM has explained, an exiting Transmission Owner will have opportunities 
to seek further cost recovery as needed.  The provisions put Transmission Owners on notice 
of the RBP-related commitments that must be honored in order to maintain reliability in 
PJM, which should be among a Transmission Owner’s considerations when weighing the 
costs and benefits of exiting.   
Proposed Tariff, Attachment DD, section 18.7(b) provides two avenues through 
which an exiting Transmission Owner may honor its responsibilities.  First, it may enter 
into an agreement with the appropriate RBP Resource(s) to negotiate “appropriate rates, 
terms, and conditions” necessary to preserve its RBP commitments.  This option would 
 
302 AEP Limited Protest at 13-15. 
303 Id. at 15-17.

101 
permit the Transmission Owner to develop cost recovery provisions that it believes are 
appropriate for preserving the ability of the RBP Resource(s) to continue operating in PJM.   
Only if an exiting Transmission Owner opts not to enter into an agreement (or does 
not reach agreement with the RBP Resource(s)) that the next option becomes available.  
This second option, then, requires the exiting Transmission Owner to pay “all forward 
obligations on an accelerated basis.”  As discussed in the July 31 Filing, such cost recovery 
is necessary to ensure that the load remaining in PJM is not forced to bear the costs of 
increased RBP charges resulting from a unilateral business decision made by the exiting 
Transmission Owner.304   
Even here, there are two additional opportunities for the exiting Transmission 
Owner to advocate for further cost recovery.  First, proposed Tariff, Attachment DD, 
section 18.7(b) makes clear that the costs of “all forward obligations” will be subject to 
Commission review, meaning that the exiting Transmission Owner would have the 
opportunity to dispute any allocated costs either before the filing or once it is filed.  Second, 
as PJM explained in the July 31 Filing:  
While the exiting Transmission Owner would be initially 
responsible to pay for the costs necessary to ensure no RBP 
Resource becomes a stranded asset, nothing in PJM’s proposal 
would preclude such a Transmission Owner from seeking to recover 
any such costs from the relevant large loads.305   
Therefore, the exiting Transmission Owner is in no way prevented from seeking further 
cost recovery from load remaining in PJM, should it believe further payment is warranted. 
AEP asserts that load outside of PJM is “similarly situated load that stays in PJM,” 
insofar as load remaining in PJM may benefit from offsets, while load outside of PJM will 
 
304 July 31 Filing, Transmittal Letter at 94-95. 
305 Id. at 95.

102 
be required to pay more.306  Contrary to such an assertion, load that leaves PJM with an 
exiting Transmission Owner would no longer be obligated under the PJM Tariff to pay any 
applicable RBP Charges while load that remains in PJM would be bound by the Tariff and 
required to pay applicable RBP Charges.  This distinction is material to the “similarly 
situated” inquiry,307 as it demonstrates that it is indeed just and reasonable to treat these 
two differently situated loads differently.  This is also consistent with how the Commission 
has previously examined whether two different loads were similarly situated.308 
3. 
The proposed Tariff language is consistent with Commission 
precedent regarding RTO withdrawal and does not change any 
existing exit processes or commitments. 
AEP’s protest includes an extensive background on the “current terms” for 
withdrawing from PJM and calls into question whether the responsibilities set forth in 
proposed Tariff, Attachment DD, section 18.7 would alter existing non-RBP 
responsibilities for Transmission Owners that seek to exit PJM.309  To be clear, as discussed 
 
306 AEP Limited Protest at 14-15. 
307 See N.Y. Indep. Sys. Operator, Inc., 162 FERC ¶ 61,124, at P 10 (2018) (“To say that entities are similarly 
situated does not mean that there are no differences between them; rather, it means that there are no 
differences that are material to the inquiry at hand.” (citing Fla. v. Long, 108 S. Ct. 2354, 2358 (1998); City 
of Los Angeles v. Lyons, 103 S. Ct. 1660, 1663 (1983))). 
308 See, e.g., Am. Elec. Power Serv. Corp. v. Midcontinent Indep. Sys. Operator, Inc., 168 FERC ¶ 61,176, at 
P 32 (2019) (“We also find that it is not unduly discriminatory for [Midcontinent Independent System 
Operator, Inc. (“MISO”)] to impose non-market-to-market congestion charges on loads pseudo-tied out of 
MISO into SPP (e.g., the Minden load) but not impose those charges for load physically located within SPP.  
The Minden load is not similarly situated to load located outside of MISO’s footprint, because Minden’s load 
is physically located in MISO and, thus, AEP imposes congestion costs on the MISO transmission system 
when it serves this load.” (footnote omitted)); City of Alameda v. Pac. Gas & Elec. Co., 176 FERC ¶ 61,013, 
at P 70 (“In this case, we find that Alameda’s load and PG&E’s retail load are not similarly situated.  Due to 
the configuration of Alameda’s and PG&E’s systems, PG&E customers on the Oakland-C system cannot be 
fed from anywhere else except from the Oakland-C bus during an N-1 contingency, whereas Alameda is able 
to transfer its load to be fed from the Oakland-J bus.”), order addressing arguments raised on reh’g & 
providing clarification, 177 FERC ¶ 61,038 (2021). 
309 AEP Limited Protest at 20-27.

103 
further, below, the proposed Tariff language does not, and is not intended to, alter any of 
these existing responsibilities.   
AEP relies heavily on the Duquesne proceedings, in which Duquesne Light 
Company (“Duquesne”) sought to exit PJM and join MISO, but ultimately “rejoined” 
PJM.310  The Commission’s discussion and analysis in the Duquesne proceedings provide 
some of the foundational principles governing withdrawal from RTOs/ISOs.  While PJM 
does not take issue with these Duquesne principles reiterated by AEP, the Commission 
should recognize that the exit provisions proposed in the instant filing are entirely 
consistent with them.  First, RBP commitments are established at the time of the RBP and 
are set for 15 years.311  Therefore, a Transmission Owner exiting PJM during this 15-year 
commitment period would be obligated to honor its capacity responsibilities for this period.   
In Duquesne II, as AEP explains, the Commission found that Duquesne would be 
responsible for costs that are “fixed” at the time the costs are assigned, but it would not be 
responsible for costs that are “not fixed” and are instead reallocated on an annual basis.312 
Regarding capacity costs specifically, AEP cites to both the RAA and Duquesne I for the 
proposition that an exiting LSE is responsible for capacity costs through the end of the 
Delivery Year during which it provided notice of withdrawal, and if it provided notice after 
the auction parameters were posted, the exiting LSE would be responsible for costs of that 
Delivery Year.313   
 
310 Duquesne Light Co., 122 FERC ¶ 61,039 (2008) (“Duquesne I”); Midwest Indep. Transmission Sys. 
Operator, Inc., 124 FERC ¶ 61,219 (2008) (“Duquesne II”) (collectively, “Duquesne”). 
311 See July 31 Filing, proposed Tariff, Attachment DD, section 18.4 (“The Reliability Backstop Procurement 
shall offer commitments for RBP UCAP MW for a fixed period of fifteen (15) Delivery Years . . . .”). 
312 AEP Limited Protest at 22-23 (citing Duquesne II at P 168). 
313 Id. at 25-26 (citing RAA, sections 5.1.1-5.1.3(a), 7.2, 7.2A, 11.1-11.3; Duquesne I at PP 83, 93).

104 
None of these holdings undermine PJM’s proposed treatment of RBP commitments 
in the event of a Transmission Owner exiting PJM.  Namely, while the exact costs may not 
be known given that settlements will account for RPM Auction outcomes under a contract 
for difference settlement structure, all of the pertinent information necessary to calculate 
the charges for an RBP Resource selected through the RBP will be known and fixed for a 
15-Delivery Year term.  This is appropriate given the unique nature of the RBP, which is 
a one-time effort to ensure reliability throughout PJM in a predictable and efficient manner.   
In Duquesne II, the Commission emphasized that its decision regarding capacity 
obligations was rooted in the fact that capacity was procured for Duquesne.  For example, 
the Commission found that Duquesne was “liable for the costs incurred in the prior auctions 
because the auctions were conducted while Duquesne was a member, [and] the auction 
obtained capacity based on Duquesne’s load in order to ensure the reliability of the 
Duquesne zone.”314  Capacity costs are unlike high voltage transmission projects, the 
Commission continued, because they “were not undertaken specifically to support 
Duquesne’s load or the reliability of that load, but would have occurred regardless of 
whether Duquesne was a member of PJM.”315  Critically, the Commission also appreciated  
that Duquesne should not be able to escape responsibility for capacity committed on its 
behalf:   
In this case, Duquesne understood that PJM was procuring capacity 
on its behalf and therefore should be obligated to pay for that 
capacity.  Indeed, allowing Duquesne to escape its obligations to pay 
for the capacity acquired on its behalf will force PJM to collect the 
 
314 Duquesne II at P 169. 
315 Id.

105 
amount it is obligated to pay the generators from the remaining 
participants in PJM, hardly a just and reasonable result.316   
The Commission even contemplated how PJM could mitigate capacity costs for Duquesne, 
including by “negotiat[ing] to ensure that Duquesne will be able to use the capacity it has 
acquired to meet its reliability obligations when it withdraws from PJM,”317 and this is in 
keeping with the spirit of PJM’s proposed Tariff revisions which provide flexibility for 
negotiated bilateral agreements, pseudo-ties, and flat payment for RBP costs subject to 
Commission approval. 
In sum, the exit provisions proposed by PJM in the instant proceeding are consistent 
with Commission precedent, particularly in light of the urgency with which PJM must 
acquire and maintain capacity in this one-time procurement. 
4. 
The proposed Tariff language on exit responsibilities is properly 
located in the Tariff and the RAA. 
Several intervenors filed comments contending that the inclusion of these proposed 
exit responsibility Tariff provisions violated the CTOA and/or should have been included 
in the CTOA rather than the Tariff and RAA.318  To the contrary, as discussed below, these 
provisions are not required to be in the CTOA, as they are not and do not relate to or affect 
transmission-related costs. 
The July 31 Filing makes clear that if a Transmission Owner makes the business 
decision to exit PJM, “the treatment of RBP Resources and load that has been allocated 
RBP Charges is, at bottom, a matter of close-out or settlement consequences of the RBP 
and thus properly addressed in [proposed] Tariff, Attachment DD [section 18].  The 
 
316 Duquesne I at P 89 (footnote omitted). 
317 Id. PP 95-97. 
318 Indicated TOs Protest at 2, 4-8; PPL Limited Protest and Request for Clarification at 3-7.

106 
departing RBP Resource’s UCAP MW and/or the departing load’s proportional share of 
the remaining term [contract for difference] are both incident to the RBP framework.”319  
None of the arguments against inclusion of these provisions in proposed Tariff, 
Attachment DD, section 18, respond to this characterization.  Further, and tellingly, none 
argue that the initial cost allocations proposed in Tariff, Attachment DD, section 18.3 are 
related transmission costs.  If they are not transmission costs when they are being allocated, 
the mere fact that an exiting Transmission Owner will bear initial responsibility for 
honoring RBP Resource commitments does not make them so.  Thus, it is appropriate for 
an exiting Transmission Owner, who has made the business decision to leave PJM, to take 
responsibility for commitments that it has advance notice of through these proposed Tariff 
provisions.  The proposed exit provisions are located in proposed Tariff, Attachment DD, 
section 18.7, and the Tariff is applicable to all entities participating in PJM.320   
5. 
The proposed Tariff revisions do not violate the separation of 
functions requirements of the Commission. 
PPL asserts that the proposed Tariff revisions violate the Commission’s Standards 
of Conduct contained in 18 C.F.R. part 358 regarding separation of functions “whereby the 
transmission function employees of a transmission-owning public utility must operate 
independently of the marketing function employees.”321  But PJM is not proposing to 
permit “the sale for resale in interstate commerce, or the submission of offers to sell in 
interstate commerce, of electric energy or capacity.”322  Rather, the proposed requirements 
 
319 July 31 Filing, Transmittal Letter at 96. 
320 This addresses concerns raised by PPL that since not all LSEs have executed the RAA, they may not be 
subject to the exit requirements.  PPL Limited  Protest and Request for Clarification at 8-9. 
321 PPL Limited Protest and Request for Clarification at 7-8. 
322 18 C.F.R. § 358.3(c)(1).

107 
are merely intended to honor obligations that would have pre-existed the exit of a 
Transmission Owner from PJM.  Furthermore, in practice, the separation of functions 
principles have been applied in the context of  affiliate transactions involving common use 
of marketing-related employees.323  In any event, if a Transmission Owner exiting PJM 
were to have concerns about potential violations under 18 C.F.R. part 358, PJM notes that 
activity that may otherwise violate separation of functions is permissible, pursuant to 18 
C.F.R. § 358.2(d) and 18 C.F.R. § 358.1(d), respectively, where ordered by the 
Commission or where the Commission has granted waiver of such requirements. 
II. 
CONCLUSION 
PJM asks that the Commission consider this Answer and accept the proposed Tariff 
revisions in this docket, effective September 29, 2026, as requested. 
 
 
 
 
 
 
 
Respectfully submitted, 
 
/s/ Vivian W. Chum   
     
Craig Glazer 
Vice President – Federal Government Policy 
PJM Interconnection, L.L.C. 
1200 G Street, NW, Suite 600 
Washington, D.C.  20005 
(202) 423-4743 
craig.glazer@pjm.com 
 
Chenchao Lu 
Associate General Counsel 
PJM Interconnection, L.L.C. 
2750 Monroe Boulevard 
Audubon, PA  19403 
(610) 666-2255 
chenchao.lu@pjm.com 
Ryan J. Collins 
Vivian W. Chum 
Anne Marie Hirschberger 
Wright & Talisman, P.C. 
1200 G Street, NW, Suite 600 
Washington, D.C.  20005 
(202) 393-1200 
collins@wrightlaw.com 
chum@wrightlaw.com 
hirschberger@wrightlaw.com 
On Behalf of 
PJM Interconnection, L.L.C. 
September 10, 2026 
 
 
 
 
 
 
323 See, e.g., Buckeye Plains Solar Project, LLC, 189 FERC ¶ 61,101, at P 20 (2024).

CERTIFICATE OF SERVICE 
 
I hereby certify that I have this day served the foregoing document upon each 
person designated on the official service list compiled by the Secretary in this proceeding. 
 
Dated at Washington, D.C., this 10th day of September 2026. 
 
 
 
 
 
 
 
 
 /s/ Vivian W. Chum  
Vivian W. Chum 
Wright & Talisman, P.C. 
1200 G Street, NW, Suite 600 
Washington, DC  20005 
chum@wrightlaw.com 
(202) 393-1200 
 
 
Attorney for 
PJM Interconnection, L.L.C.

Appendix A 
 
Protests, Comments, Requests for Clarification, and Answers Filed to Date  
Docket No. ER26-3380-000

i 
Appendix A 
Protests, Comments, Requests for Clarification, and Answers Filed to Date  
Docket No. ER26-3380-000 
• Comments of Advanced Energy United (Aug. 21, 2026) (“AEU Comments”) 
• Motion to Intervene and Initial Comments of Amazon Energy LLC (Aug. 21, 2026) 
(“Amazon Comments”) 
• Limited Protest of American Electric Power Service Corporation (Aug. 21, 2026) 
(“AEP Limited Protest”) 
• Comments of American Municipal Power, Inc. (Aug. 21, 2026) (“AMP 
Comments”) 
• Motion for Leave to Answer, and Answer, of the Attorney General of the 
Commonwealth of Kentucky (Sept. 2, 2026) (“Kentucky Attorney General 
Answer”) 
• Motion to Intervene and Comments of Base Power Inc. (Aug. 21, 2026) (“Base 
Power Comments”) 
• Comments of Blue Ridge Power Agency (Aug. 21, 2026) (“Blue Ridge 
Comments”) 
• Request for Clarification of Calibrant Energy (Aug. 21, 2026) (“Calibrant Request 
for Clarification”) 
• Limited Protest of Constellation Energy Generation, LLC (Aug. 21, 2026) 
(“Constellation Limited Protest”) 
• Motion for Leave to Answer and Answer of Constellation Energy Generation, LLC 
(Sept. 8, 2026) (“Constellation Answer”) 
• Motion to Intervene and Comments of CPV Power Holdings, LP (Aug. 21, 2026) 
(“CPV Comments”) 
• Comments of the Data Center Coalition (Aug. 21, 2026) (“DCC Comments”) 
• Partial Protest and Comments of Dominion Energy Services, Inc. (Aug. 21, 2026) 
(“Dominion Partial Protest and Comments”) 
• Protest of East Kentucky Power Cooperative (Aug. 21, 2026) (“EKPC Protest”) 
• Motion for Leave to File Limited Answer and Limited Answer of East Kentucky 
Power Cooperative (Sept. 4, 2026) (“EKPC Limited Answer”) 
• Comments and Protest of E-Cubed Policy Associates, L.L.C. and Motion for Leave 
to File One Day Out of Time (Aug. 22, 2026) (“E-Cubed Protest”)

ii 
• Comments of Equinix Inc. on the PJM Interconnection, L.L.C. Filing Regarding Its 
Reliability Backstop Procurement to Address Reliability Adequacy Concerns 
Stemming from Large Loads (Aug. 21, 2026) (“Equinix Comments”) 
• Comments and Protest of FirstEnergy Service Company (Aug. 21, 2026) 
(“FirstEnergy Comments and Protest”) 
• Comments of Google LLC (Aug. 21, 2026) (“Google Comments”) 
• Comments of the Organization of PJM States, Inc. (Aug. 21, 2026) (“OPSI 
Comments”) 
• Illinois Commerce Commission Comments (Aug. 19, 2026) (“ICC Comments”) 
• Protest of the Independent Market Monitor for PJM (Aug. 21, 2026) (“IMM 
Protest”) 
• Protest of the Indicated PJM Transmission Owners (Aug. 21, 2026) (“Indicated 
TOs Protest”) 
• Comments of the Institute for Policy Integrity at New York University School of 
Law on PJM Interconnection, L.L.C. Section 205 Filing to Implement Reliability 
Backstop Procurement (Aug. 21, 2026) (“NYU Institute Comments”) 
• Protest, Motion to Reject, and Alternative Request for the Imposition of Conditions 
of Joint Consumer Advocates (Aug. 21, 2026) (“JCA Protest”) 
• Limited Protest of the NRG Companies (Aug. 21, 2026) (“NRG Limited Protest”) 
• Comments of the New Jersey Board of Public Utilities (Aug. 21, 2026) (“NJ BPU 
Comments”) 
• Motion to Intervene and Protest of Nicholas Max Neal and David Neal, Delaware 
Standard Offer Service Ratepayers (Aug. 20, 2026) (“Nicholas Max Neal and 
David Neal Protest”) 
• Comments of North Carolina Electric Membership Corporation (Aug. 21, 2026) 
(“NCEMC Comments”) 
• Protest of Northern Virginia Electric Cooperative, Inc. (Aug. 21, 2026) (“NOVEC 
Protest”) 
• Protest and Request for Rejection of Filing or in the Alternative for Evidentiary 
Hearings and/or Settlement Proceedings by Office of the Ohio Consumers’ Counsel 
(Aug. 21, 2026) (“OCC Protest”) 
• Comments of the Public Utilities Commission of Ohio’s Office of the Federal 
Energy Advocate (Aug. 21, 2026) (“Ohio FEA Comments”) 
• Comments of Ohio Energy Leadership Council (Aug. 21, 2026) (“Ohio ELC 
Comments”)

iii 
• Comments of Old Dominion Electric Cooperative (Aug. 21, 2026) (“ODEC 
Comments”) 
• Protest of the Pennsylvania Office of Consumer Advocate Re: Reliability Backstop 
Procurement to Address Resource Adequacy Concerns Stemming from New Load 
Adjustments (Aug. 21, 2026) (“PA OCA Protest”) 
• Comments of Persistence Analytics Group Regarding Pre-Procurement 
Assumption Verification and Revalidation (Aug. 17, 2026) (“Persistence Analytics 
Comments”) 
• Supplemental Comments of Persistence Analytics Group LLC Regarding Cost-
Causation Revalidation (Sept. 2, 2026) (“Persistence Analytics Supplemental 
Comments”) 
• Comments on PJM’s Reliability Backstop Procurement Proposal on Behalf of PJM 
Industrial Customer Coalition (Aug. 21, 2026) (“PJMICC Comments”) 
• Motion to Intervene, Limited Protest, and Request for Clarification of PPL Electric 
Utilities Corporation (Aug. 21, 2026) (“PPL Limited Protest and Request for 
Clarification”) 
• Limited Protest of Public Interest Organizations (Aug. 21, 2026) (“PIOs Limited 
Protest”) 
• Comments of the Public Service Commission of West Virginia (Aug. 21, 2026) 
(“PSCWV Comments”) 
• Motion to Intervene and Protest of Retail Energy Supply Association (Aug. 21, 
2026) (“RESA Protest”) 
• Comments of Solar Energy Industries Association (Aug. 21, 2026) (“SEIA 
Comments”) 
• Comments of Southern Maryland Electric Cooperative, Inc. (Aug. 21, 2026) 
(“SMECO Comments”) 
• Motion to Intervene and Request for Clarification of Talen Energy Corporation 
(Aug. 21, 2026) (“Talen Request for Clarification”) 
• Motion to Intervene and Request for Clarification, or in the Alternative, Limited 
Protest of Tract Holding Company I, LLC (Aug. 21, 2026) (“Tract Request for 
Clarification or Limited Protest”) 
• Limited Protest of Vistra Corp. (Aug. 21, 2026) (“Vistra Protest”) 
• Comments of Voltus (Aug. 21, 2026) (“Voltus Comments”)