ER26-3380-000 · 2026-09-29 · FERC

Order accepting PJM's Reliability Backstop Procurement, suspending it to February 28, 2027, and establishing further procedures

196 FERC ¶ 61,245 
UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
Before Commissioners:  Laura V. Swett, Chairman; 
                                        David Rosner, Lindsay S. See, 
                                        Judy W. Chang, and David LaCerte. 
PJM Interconnection, L.L.C. 
Docket Nos. ER26-3380-000 
EL26-108-000
ORDER ACCEPTING RELIABILITY BACKSTOP PROCUREMENT AND 
ESTABLISHING FURTHER PROCEDURES 
(Issued September 29, 2026) 
On July 31, 2026, as supplemented on August 14, 2026, PJM submitted proposed 
changes to its Open Access Transmission Tariff (OATT or Tariff) and Reliability 
Assurance Agreement (RAA),1 pursuant to section 205 of the Federal Power Act (FPA),2
to establish the Reliability Backstop Procurement (RBP).  The RBP is a one-time 
procurement of new capacity to address significant resource adequacy challenges 
primarily driven by an influx of large loads.3  As discussed below, we accept the 
proposed RBP for filing, suspend it for five months, effective February 28, 2027,    
subject to refund, and establish a paper hearing.  We also establish an FPA section 206 
proceeding.4
We find that certain aspects of PJM’s proposal are just and reasonable.  With 
respect to other aspects of PJM’s proposal that may be unjust and unreasonable, we direct 
further briefing regarding potential alternative approaches that the Commission believes 
1 Capitalized terms that are not defined in this order have the meaning specified in 
the OATT and RAA. 
2 16 U.S.C. § 824d. 
3 PJM’s proposed rules governing the RBP are primarily set forth in proposed 
Tariff, Attachment DD, section 18, with additional conforming revisions and new 
provisions in other sections of:  (1) Attachment DD; (2) RAA, Article 7, sections 7.2B 
and 7.2C; (3) RAA, Schedule 8.1.D; and (4) Tariff, Definitions.  See Appendix A for 
tariff records accepted and suspended in this order. 
4 16 U.S.C. § 824e.

Docket Nos. ER26-3380-000 and EL26-108-000 
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may be just and reasonable.  We therefore establish paper hearing procedures and a 
process by which the Commission may potentially revise those provisions consistent with 
FPA section 206.   
Recognizing the looming capacity shortfall facing PJM, we encourage PJM to 
consider the issues we raise in this order and determine the most expeditious path to 
resolving them.  In particular, we encourage PJM to swiftly submit a new FPA section 205 
filing without delay.  That new filing may in turn obviate the need for the paper hearing 
procedures that we establish here and could expedite a potential RBP auction.  
I.
Background 
PJM conducts a Base Residual Auction (BRA) to procure resource commitments 
sufficient to meet reliability requirements in the PJM region for a given delivery year, 
which spans from June 1 to May 31.5  The BRA and three Incremental Auctions are the 
Reliability Pricing Model (RPM) Auctions for a given delivery year. 
In December 2025, PJM announced that a BRA had cleared significantly below 
PJM’s reliability requirement for the first time in the auction’s history.  The 2027/2028 
BRA cleared 6,623 MW6 short of the reliability requirement, when also accounting for 
Fixed Resource Requirement (FRR) resources.7  The largest driver of the shortfall was 
5,250 MW of load growth forecast for that delivery year, nearly 5,100 MW of which was 
5 PJM, Intra-PJM Tariffs, OATT, attach. DD, § 5.4 (Reliability Pricing Model 
Auctions) (10.0.0), § 5.4(a). 
6 All supplier MW values in this order are expressed in unforced capacity (UCAP). 
7 Both the BRA and the FRR Alternative are designed to secure enough power 
supply to ensure that sufficient capacity will be available to meet peak customer demand.  
The FRR Alternative allows Load-Serving Entities (LSE) to elect to meet their resource 
adequacy needs with their own resources.  See RAA SCHEDULE 8.1.D, RAA 
SCHEDULE 8.1.D-FRR Capacity Plans (14.2.0).

Docket Nos. ER26-3380-000 and EL26-108-000 
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due to data centers.8  The 2027/2028 BRA, which cleared at the temporary price cap of 
$333.44/MW-day, was the third BRA in a row to clear at historically high prices.9
In January 2026, the White House National Energy Dominance Council (NEDC) 
and the governors of all 13 PJM states released a document titled “Statement of 
Principles Regarding PJM” (NEDC/PJM Governors’ Principles).10  The document urged 
PJM to file tariff revisions with the Commission to “[p]rovide 15-year price certainty for 
new capacity resources,” which “can be accomplished by holding a Reliability Backstop 
Auction to procure new capacity resources commencing no later than September 2026.”  
Noting the unique risks data centers pose to resource adequacy, the document urged PJM 
to allocate the costs of any new capacity procured to load-serving entities with data 
centers that have not self-procured new capacity or agreed to be curtailable, with any 
remaining costs allocated to load-serving entities based on their remaining net-short 
positions. 
Also in January 2026, the PJM Board announced its decision on a Critical Issue 
Fast Path (CIFP) process addressing large load issues in PJM, which, among other things, 
included accelerating a backstop capacity procurement.11
8 PJM Inside Lines, “PJM Auction Procures 134,479 MW of Generation 
Resources,” (Dec. 17, 2025) https://insidelines.pjm.com/pjm-auction-procures-134479-
mw-of-generation-resources/.  In PJM’s 2026 load forecast released in January, PJM cut its 
peak demand forecasts for summer 2027 and summer 2028 by 4,000 MW and 4,400 MW, 
respectively, citing tighter vetting of Load Adjustment requests and revised electric vehicle 
and economic assumptions.  PJM, 2026 PJM Load Forecast Report 4-5 (Jan. 2026), 
https://www.pjm.com/-/media/DotCom/library/reports-notices/load-forecast/2026-load-
report.pdf.  
9 While clearing at historically high prices, these previous two BRAs did not clear 
significantly below PJM’s reliability requirement.  See PJM, 2025/2026 Base Residual 
Auction Report (July 30, 2024), https://www.pjm.com/-/media/DotCom/markets-
ops/rpm/rpm-auction-info/2025-2026/2025-2026-base-residual-auction-report.pdf; PJM, 
2026/2027 Base Residual Auction Report (July 22, 2025), https://www.pjm.com/-
/media/DotCom/markets-ops/rpm/rpm-auction-info/2026-2027/2026-2027-bra-report.pdf. 
10 U.S. Department of Energy, Statement of Principles Regarding PJM (Jan. 2026), 
https://www.energy.gov/documents/statement-principles-regarding-pjm.  
11 PJM, Board Decisional Letter on Critical Issue Fast Path - Large Load 
Additions (Jan. 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.

Docket Nos. ER26-3380-000 and EL26-108-000 
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In March 2026, the White House released the Ratepayer Protection Pledge to 
assure that new large loads will, at a minimum, “build, bring, or buy the new generation 
resources and electricity needed to satisfy their new energy demands, paying the full cost 
of those resources.”12  Many utilities, cooperatives, data center developers, and governors 
have signed the pledge. 
In April 2026, the PJM Board issued a letter initiating a targeted CIFP process      
to engage stakeholders in the development of the RBP.13  Soon after, PJM proposed a 
two-path mechanism for the RBP:  a central procurement path (i.e., the RBP auction of 
the instant filing) and a facilitated bilateral contracting matchmaking path that PJM states 
requires no filing with the Commission.14  PJM plans to run this latter path in parallel 
with the RBP auction to streamline direct contracting between supply and demand.  
According to the PJM Board, bilateral contracting is “highly preferred among 
members.”15
In June 2026, PJM issued a bilateral matchmaking request for proposals, with 
responses due July 21, 2026, at which time consultant Charles River Associates 
commenced the bilateral matchmaking process.16  This process is intended to be iterative 
and will continue for six to nine months.  Supply-side resources in the bilateral matching 
12 The White House, President Trump’s Ratepayer Protection Pledge Secures 
American AI Dominance, Protects Consumers (July 2026), 
https://www.whitehouse.gov/releases/2026/07/president-trumps-ratepayer-protection-
pledge-secures-american-ai-dominance-protects-consumers/ (identifying 282 utilities, 
cooperatives, and data center developers and 23 governors that have joined the Ratepayer 
Protection Pledge).   
13 PJM, Critical Issue Fast Path (CIFP) (Apr. 2026), https://www.pjm.com/-
/media/DotCom/about-pjm/who-we-are/public-disclosures/2026/20260408-cifp-rbp-
initiation-letter.pdf. 
14 Transmittal at 30. 
15 PJM, CIFP Reliability Backstop Procurement – PJM Board Decision 1        
(July 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-
disclosures/2026/20260727-cifp-reliability-backstop-procurement-pjm-board-
decision.pdf.  See also Transmittal at 30 (“Throughout the underlying stakeholder 
process, PJM members have expressed a strong preference for bringing new capacity to 
the PJM system voluntarily through bilateral contracting rather than through the RBP.”). 
16 Charles River Associates, PJM Reliability Backstop Procurement            
Bilateral Request for Proposal (RFP) (June 2026), https://www.pjm.com/-
/media/DotCom/committees-groups/cifp-rbp/postings/pjm-bilateral-rfp-document.pdf.

Docket Nos. ER26-3380-000 and EL26-108-000 
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process that do not form agreements may bid into the RBP auction.  Bidders will not      
be permitted to then exit the RBP auction process to enter bilateral arrangements, but 
supply-side resources that are not selected in the RBP auction may re-engage in bilateral 
matching. 
On May 27, 2026, PJM announced the results of an April survey to gauge interest 
from load in the RBP.17  PJM states that the response revealed substantial large load 
interest from 21 entities representing 47 potential large load projects in the PJM Region; 
those projects average 850 MW each, with a median size of 300 MW.  PJM explains that 
the supply-side response was also significant, with 397 potential supply-side projects by 
87 entities and approximately 136 GW in total potential capacity.  Of the supply-side 
projects, 72% indicated a readiness to engage with their large load counterparts 
immediately, while 91% of the large load projects indicated the same. 
On June 30, 2026, the Members Committee voted on 13 RBP auction proposals as 
an advisory to the PJM Board.18  Stakeholders endorsed only one proposal, meaning that 
it received at least two-thirds sector-weighted support.  That support (75%) went to a 
proposal sponsored by the Data Center Coalition (DCC) and a coalition of Electric 
Distributors.19  PJM’s own proposal received only 30% support.20  The DCC/Electric 
Distributors coalition proposed a “subscription model” in which large loads wishing to 
participate would provide their LSE with a MW volume for PJM to purchase on their 
behalf.  PJM instead proposed to base its procurement target on the shortage in the 
2028/2029 BRA and to allocate costs to Electric Distributor zone/areas pro rata based    
on forecasted load adjustments.  In addition, the DCC/Electric Distributors coalition’s 
proposal included a locational constraint that allowed only 500 MW to serve the        
Mid-Atlantic Dominion reserve sub-zone, which was intended to prevent future         
17 Transmittal at 18 (citing Charles River Associates, PJM Reliability Backstop 
RFI Summary (May 2026), https://www.pjm.com/-/media/DotCom/committees-
groups/cifp-rbp/2026/20260527/20260527-informational-only---reliability-backstop-rfi-
summary---charles-river-associates.pdf (Charles River Associates Survey Results)). 
18 Id. at 20. 
19 PJM Members Committee, Supplemental Voting Results (June 2026), 
https://www.pjm.com/-/media/DotCom/committees-
groups/committees/mc/2026/20260630-special/mc-voting-results---agenda-item-3o---
joint-edcs-and-data-center-coalition-rbp-proposal.pdf. 
20 PJM Members Committee, Supplemental Voting Results (June 2026), 
https://www.pjm.com/-/media/DotCom/committees-
groups/committees/mc/2026/20260630-special/mc-voting-results---agenda-item-3l---
pjm-rbp-proposal.pdf.

Docket Nos. ER26-3380-000 and EL26-108-000 
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BRA price separation due to RBP resources being electrically separated from data 
centers.  PJM’s proposal had no locational constraints.  Despite these differences,      
many of the core components of the two proposals were the same, including resource 
commitments up to the 2042/2043 delivery year, requiring a resource in-service date     
by the 2032/2033 delivery year, a must-offer RPM requirement with contracts for 
differences, and similar new supply qualifications, shortfall penalties, and supplier 
collateral requirements. 
On July 14, 2026, PJM announced that the 2028/2029 BRA cleared short of the 
PJM Region’s reliability requirement (when also accounting for FRR resources) at a 
clearing price at the temporary price cap of $325/MW-day.21
On July 27, 2026, the PJM Board announced that it had adopted PJM’s proposal 
with three “targeted changes” to adopt certain concepts that had roots in the DCC/Electric 
Distributors coalition’s proposal.22  First, the PJM Board added two RBP opt-outs:  one 
that applies to qualifying cooperatives and municipal utilities, and one that applies to 
Electric Distributor zone/areas that are addressing their capacity needs through state peak 
shaving adjustment programs.  Second, the PJM Board proposed to cap the MW-weighted 
average cost of accepted supply offers at $555/MW-day.  Third, the PJM Board added 
stringent LSE collateral requirements to address potential defaults on the demand side.  
The PJM Board explained that it did not adopt the DCC/Electric Distributors coalition’s 
entire proposal because a voluntary subscription framework would not provide sufficient 
assurance that the RBP would procure enough capacity.23
21 PJM Inside Lines, “PJM Capacity Auction Procures 138,318 MW of  
Generation Resources as Work Continues to Address Growing Electricity Demand,” 
https://insidelines.pjm.com/pjm-capacity-auction-procures-138318-mw-of-generation-
resources-as-work-continues-to-address-growing-electricity-demand/. 
22 PJM, CIFP Reliability Backstop Procurement – PJM Board Decision
(July 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-
disclosures/2026/20260727-cifp-reliability-backstop-procurement-pjm-board-
decision.pdf (“targeted changes” highlighted in blue).  See Transmittal at 22. 
23 Paula Conboy, Chair, PJM Board of Managers, Board Decisional Letter on 
Critical Issue Fast Path – Reliability Backstop Procurement and Connect and Manage,  
at 1 (July 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-
disclosures/2026/20260727-board-decisional-letter-on-cifp-reliability-backstop-
procurement-and-connect-and-manage.pdf.

Docket Nos. ER26-3380-000 and EL26-108-000 
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II.
Filing 
On July 31, 2026, PJM submitted revisions to the Tariff and RAA to establish the 
RBP, a one-time procurement of new capacity to address resource adequacy challenges 
primarily driven by an influx of large loads.  According to PJM, the goal of the RBP is   
to obtain commitments of new RBP UCAP MW24 from eligible new resources, called 
RBP Resources, for a fixed term of up to 15 years, starting with the 2028/2029 delivery 
year at the earliest and ending no later than the 2042/2043 delivery year.25  PJM states 
that committing supply for terms of up to 15 years creates revenue certainty for the 
supply resources, generally can reduce financial and development risk, and may improve 
financing opportunities through lower capital costs or more favorable financing terms.26
Participants in the RBP are:  (1) sellers with RBP Sell Offers submitted on    
behalf of RBP Resources; and (2) PJMSettlement, Inc., acting as a counterparty on behalf 
of buyers, i.e., LSEs.27  PJM states that the RBP aims to procure capacity equal to the 
6,831 MW shortfall in the 2028/2029 BRA (Initial RBP Target), adjusted downward to 
reflect qualifying new capacity (Qualifying RBP Offset UCAP MW) serving new load 
and certain qualifying Electric Distributors that elect and meet requirements to opt out of 
the RBP (Opt-Out UCAP MW).  The Final RBP Target is the Initial RBP Target after 
downward adjustments.  Pursuant to the proposed Tariff provisions, new load is load that 
has an executed electric service agreement or transmission service agreement indicating 
that the load will come online during the 2027/2028 or 2028/2029 delivery year.28
To avoid double procurement, PJM proposes to require all available committed 
RBP UCAP MW to offer into the RPM Auctions as a price-taker, i.e., $0/MW-day 
UCAP, beginning with the first RPM Auction following the RBP commitment, for the 
applicable offered delivery year in which the term of the committed RBP UCAP MW 
24 PJM’s filing includes several newly defined terms.  See PJM, Intra-PJM Tariffs, 
C-D, OATT Definitions – C-D (47.0.0); id., E-F, OATT Definitions - E - F (45.0.0); id., 
O-P-Q, OATT Definitions - O - P - Q (39.0.0); id., R-S, OATT Definitions – R - S 
(47.0.0). 
25 Transmittal at 8-9. 
26 Id. at 63-64. 
27 PJMSettlement, a non-profit subsidiary of PJM, handles credit, billing,           
and settlement functions for PJM and acts as a counterparty to PJM members’ pool 
transactions in the PJM markets on behalf of the ultimate buyer of the product.  
Transmittal at 47. 
28 Transmittal at 35; Proposed Tariff, attach. DD, § 18.2 (0.0.0), § 18.2(c).

Docket Nos. ER26-3380-000 and EL26-108-000 
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begins and continuing each subsequent delivery year through the end of the fixed term.  
All RBP Resources clearing in the RPM are paid RPM Auction Credits in accordance 
with RPM rules and are then settled based on a contract-for-difference design for the 
RBP UCAP MW.  All load that is allocated RBP Charges and participates in the RPM     
is charged or receives RBP Charges, based on the contract-for-difference settlement.  
RBP Credits and Charges are only assessed to the extent that RBP UCAP MW are 
committed in the RPM and physically available for dispatch in the relevant delivery year. 
PJM states that if the Commission accepts its filing without significant revisions, 
PJM commits to opening the RBP bid submission window on September 30, 2026, and 
closing it three weeks later on October 21, 2026.29  PJM states that a clearing and 
selection process would follow and conclude six weeks after the closing of the offer 
submission window.  PJM states that it would announce the pay-as-bid results to sellers a 
few days before the 2029/2030 BRA opens on December 9, 2026.30  PJM also commits to 
post publicly the aggregate MW procured and a MW-weighted average of the cost.31
PJM states that “to facilitate Commission approval and prompt opening of the 
RBP procurement window, PJM consents to the Commission’s exercise of authority to 
modify and/or sever the proposed Tariff and RAA language, as needed and permitted 
under section 205 of the FPA and NRG Power Marketing, LLC v. FERC, where such 
modification and/or severance is consistent with PJM’s overarching objectives in this 
filing,” and asks only that the Commission “expressly prescribe the revised rate or rule in 
its order.”32
III.
Notice of Filing and Responsive Pleadings 
Notice of PJM’s filing was published in the Federal Register, 91 Fed. Reg. 50826 
(Aug. 6, 2026), with interventions and protests due on or before August 21, 2026.  
Notices of intervention and timely-filed motions to intervene were submitted by the 
entities listed in Appendix B to this order.33  Comments and protests were submitted by 
numerous entities, as summarized below.  Answers were submitted by AEP, the 
29 Transmittal at 3 n.5, 48; Proposed Tariff, attach. DD, § 18.4 (0.0.0). 
30 Transmittal at 133. 
31 Id. at 79. 
32 Id. at 3, 130-31.  See NRG Power Mktg., LLC v. FERC, 862 F.3d 108          
(D.C. Cir. 2017) (NRG). 
33 The abbreviated names or acronyms by which these entities are referred to in 
this order are noted in Appendix B.

Docket Nos. ER26-3380-000 and EL26-108-000 
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Kentucky Attorney General, EKPC, the Market Monitor, NJBPU, NOVEC, Voltus, PJM, 
P3, PPL, Constellation, Indicated PJM TOs, and FirstEnergy.  Additional answers were 
submitted by Constellation and EKPC. 
IV.
Discussion 
A.
Procedural Matters 
Pursuant to Rule 214 of the Commission’s Rules of Practice and Procedure,        
18 C.F.R. § 385.214 (2025), the notices of intervention and timely, unopposed motions   
to intervene serve to make the entities that filed them parties to this proceeding. 
Rule 213(a)(2) of the Commission’s Rules of Practice and Procedure, 18 C.F.R. 
§ 385.213(a)(2) (2025), prohibits an answer to a protest or answer unless otherwise 
ordered by the decisional authority.  We accept the answers filed by AEP, the Kentucky 
Attorney General, EKPC, the Market Monitor, NJBPU, NOVEC, Voltus, PJM, P3, 
Constellation, PPL, Indicated PJM TOs, and FirstEnergy because they have provided 
information that assisted us in our decision-making process. 
B.
Substantive Matters 
Our preliminary analysis indicates that, while some aspects of PJM’s proposal are 
just and reasonable, other aspects of PJM’s proposal have not been shown to be just and 
reasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or 
otherwise unlawful.  PJM’s filing raises issues of material fact that cannot be resolved 
based on the record before us and that are more appropriately addressed in the paper 
hearing procedures established below.  Accordingly, we accept PJM’s proposal for filing 
and suspend it for five months to become effective February 28, 2027, subject to refund 
and to the outcome of paper hearing procedures.  Specifically, the paper hearing 
procedures should address the Commission’s potential modifications with respect to the 
portions of PJM’s existing RBP proposal that are discussed immediately below.  Aside 
from the three issues discussed directly below, we find that the other aspects of PJM’s 
RBP proposal are just and reasonable, as discussed in this order. 
We direct PJM to submit an initial brief addressing the paper hearing topics 
discussed below (cost allocation, Transmission Owner exit rules, and LSE collateral 
requirements), and to discuss in that brief whether its proposal could be just and 
reasonable if modified.  Other parties to this proceeding may also submit initial briefs    
on these topics.  Initial briefs are due 45 days from the date of this order.  However,       
we anticipate that the Commission would grant a motion to hold that briefing in this 
proceeding in abeyance if PJM submitted a new section 205 filing within 30 days from 
the date of this order.  Absent any such abeyance, responses to those initial briefs are due 
20 days after the date that initial briefs are due.  No additional answers or briefs will be 
permitted, and the Commission will look with great disfavor on any requests to extend

Docket Nos. ER26-3380-000 and EL26-108-000 
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these deadlines.  Any evidence included with the briefs shall be submitted in the form     
of affidavits accompanying the briefs.  We remind parties that their pleadings in Docket 
No. ER26-3380-000 remain part of the record in this proceeding and that they need not—
and should not—repeat their prior arguments in the paper hearing. 
We anticipate that, following the paper hearing, the Commission may need to 
direct significant modifications to certain aspects of PJM’s proposal pursuant to its 
authority under section 205(e) of the FPA34 and Western Resources, Inc. v. FERC.35
Pursuant to Western Resources, the Commission may “transform” an existing  
FPA section 205 proceeding into an FPA section 206 proceeding and “impose its own 
rate,” provided the Commission makes three requisite findings:  (1) that the utility has 
failed to show that the proposed rate is just and reasonable, (2) that the existing rate is no 
longer just and reasonable, and (3) that the substitute rate established by the Commission 
is just and reasonable.36  We anticipate that, based on the record developed through the 
paper hearing, the Commission may find that each of these three prongs is satisfied and 
impose a new rate that incorporates some of the potential modifications discussed below.  
We first discuss why PJM’s existing rate may be unjust and unreasonable, then turn to 
why each aspect of PJM’s proposal that we are setting for paper hearing may be unjust 
and unreasonable, and then discuss why PJM’s proposal may be just and reasonable if 
modified.   
In addition to establishing paper hearing procedures under FPA section 205,       
this order also establishes a new FPA section 206 proceeding in anticipation of the 
Commission directing significant modifications to certain aspects of PJM’s RBP   
proposal following the paper hearing.  We institute this FPA section 206 proceeding 
because, as discussed in the next section below, PJM’s existing Tariff may be unjust and 
unreasonable.  When the Commission directs modifications under Western Resources,     
it does so by “transform[ing]” an existing section 205 proceeding into a section 206 
proceeding and making the requisite findings.  Though we are establishing an FPA 
section 206 proceeding today (Docket No. EL26-108), we are not instituting any further 
process under FPA section 206 at this time.  
34 16 U.S.C. § 824d (“[T]he Commission may make such orders with reference 
thereto as would be proper in a proceeding initiated after it had become effective.”). 
35 9 F.3d 1568 (D.C. Cir. 1993) (Western Resources).  See Tenn. Gas Pipeline Co. 
v. FERC, 860 F.2d 446, 453-54 (D.C. Cir. 1988) (interpreting similar statutory language 
in section 4(e) of the Natural Gas Act).
36 Western Resources, 9 F.3d at 1579.

Docket Nos. ER26-3380-000 and EL26-108-000 
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While the Commission is establishing the procedures described above, we strongly 
encourage PJM to address the issues discussed in this order by submitting an alternative 
proposal pursuant to its FPA section 205 filing rights without delay.  Such a filing could 
expedite the resolution of the concerns that we have identified with certain aspects of 
PJM’s RBP proposal.  Should PJM submit a filing under FPA section 205, it should 
explain how its proposal resolves the concerns discussed in this order.37
1.
PJM’s Existing Tariff May Be Unjust and Unreasonable 
We preliminarily find that PJM’s existing Tariff may be unjust and unreasonable 
because the existing reliability backstop provisions appear to be insufficient to prevent 
the grave resource adequacy concerns that led PJM to file the instant proposal in the first 
place.  We think it clear that PJM’s ordinary instrument for procuring sufficient capacity 
to meet PJM’s reliability requirement, the RPM, has failed to keep pace with the 
unprecedented influx of large load into the PJM Region in recent years.   
The existing Reliability Backstop Auction provision in PJM’s Tariff may be unjust 
and unreasonable because it has failed to remedy these reliability concerns.38  As PJM 
states, the Reliability Backstop Auction, which was proposed over 20 years ago and has 
never been used, was not designed to respond to the circumstances surrounding PJM’s 
current capacity shortfall.39  The Reliability Backstop Auction is triggered after three 
consecutive BRAs clear with a total unforced capacity amount that is more than one 
percent below PJM’s reserve margin.40  As stated above, PJM’s last two BRAs have 
cleared more than five percent below PJM’s reserve margin.  Moreover, once the 
Reliability Backstop Auction is triggered, PJM cannot run the auction until it “make[s] a 
filing with FERC for approval to conduct a Reliability Backstop Auction.”41
The aspects of the existing Reliability Backstop Auction discussed above call into 
question the sufficiency of the current Tariff mechanism to adequately respond in a 
timely manner to the magnitude of the resource adequacy challenges that the PJM Region 
37 If PJM does make such a filing, the Commission could still modify such a filing 
under the Western Resources approach described above.  
38 PJM, Intra-PJM Tariffs, OATT, attach. DD, § 16 (Reliability Backstop) (2.0.0). 
39 Transmittal at 29. 
40 PJM, Intra-PJM Tariffs, OATT, attach. DD, § 16 (Reliability Backstop) (2.0.0), 
§ 16.3(a)(i). 
41 Id.

Docket Nos. ER26-3380-000 and EL26-108-000 
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faces today.  We therefore conclude on a preliminary basis that the existing Reliability 
Backstop Auction Tariff provisions may be unjust and unreasonable. 
2.
Certain Aspects of PJM’s Proposal Are Just and Reasonable 
a.
Seller Eligibility Requirements, Sell Offers, and RPM 
Must-Offer Requirement 
i.
Filing 
Like offset capacity, RBP Resources (i.e., resources that bid into the RBP auction) 
must have never cleared in an RPM Auction and must have an expected in-service date 
by June 1, 2032.42  PJM, however, states that because RBP Resources have longer-term 
commitments and price certainty—as compared to resources that provide offset 
capacity—PJM proposes more restrictive criteria for RBP Resources to limit them to 
those resources that have demonstrated a high likelihood of success in reaching 
commercial operation in the near term and remaining available throughout the 
commitment period.  Thus, some categories of resources eligible to be offset capacity 
cannot be RBP Resources, including resources that increase UCAP by switching fuels 
and ELCC class but do not bring on new ICAP.  Similarly, any incremental capacity 
created by new Capacity Interconnection Rights (CIRs) must also be associated with an 
increase in ICAP.  PJM states that resources relying on Surplus Interconnection Service 
to provide new UCAP MW do not qualify because these resources do not have any 
independent rights to the PJM system.43  PJM explains that, by design, a surplus resource 
can only operate while the existing resource is in service, or no more than one year after 
the deactivation of the existing resource, and when the existing resource is not operating 
and using the interconnection service.  PJM states that given the 15-year term of the RBP 
commitment period, resources need to be able to operate independently to provide 
certainty of deliverability for a 15-year term.  Finally, Demand Resources and DER 
Aggregators without identified sites and a 15-year agreement in place cannot be RBP 
Resources.
Each RBP Sell Offer must include:  (1) the quantity (MW (UCAP)) to be provided 
by the RBP Resource for each delivery year where the maximum UCAP included in an 
RBP Sell Offer shall be limited to no greater than 120% of the resource type’s most 
recent maximum Preliminary ELCC Class Ratings for 2028/2029 delivery year through 
the last posted delivery year or based on the resource’s maximum estimated unit-specific 
ELCC ratings across such period for resources with no ELCC Class Rating, multiplied by 
the resource’s ICAP; and (2) the price in $/MW-day UCAP for each delivery year 
42 Proposed Tariff, attach. DD, § 18.5 (0.0.0), § 18.5(a). 
43 Transmittal at 52-54.

Docket Nos. ER26-3380-000 and EL26-108-000 
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beginning with the first full delivery year in which the RBP UCAP MW is expected to 
provide capacity through the 2042/2043 delivery year.44  PJM states that the 120% 
quantity cap reflects the fact that a resource’s Accredited UCAP value may change from 
year to year.45  PJM argues that allowing sellers to offer amounts greater than the UCAP 
determined through current ELCC modeling allows sellers to offer their expected UCAP 
levels in future years while limiting the risk of overestimated expected UCAP values.  
PJM argues the cap represents a reasonable balance between providing the seller with 
flexibility and managing UCAP risk for load.46
Sellers are responsible for all actual Network Upgrade costs as determined through 
the interconnection process, without any subsequent adjustments to RBP Sell Offers.47
Sellers reflect in their RBP Sell Offers the anticipated cost of any Network Upgrades, 
estimated or final, associated with the RBP Resource’s provision of capacity. 
To avoid double procurement, PJM proposes to require a committed RBP Resource 
to offer its available capacity, up to the total quantity of committed RBP UCAP MW,   
into the RPM Auctions as a price-taker, i.e., $0/MW-day UCAP, beginning with the first 
RPM Auction following the RBP commitment, for the applicable offered delivery year in 
which the term of the committed RBP UCAP MW begins and continuing each subsequent 
delivery year through the end of the fixed term.48  All RBP Resources that offer and clear 
44 Proposed Tariff, attach. DD, § 18.5 (0.0.0), § 18.5(e). 
45 Transmittal at 55. 
46 PJM notes that the 120% cap is comparable to Southwest Power Pool, Inc.’s 
recently proposed cap to High Impact Large Load Generation Assessment Customer’s 
generating facility’s projected capacity accreditation value (i.e., the higher of 125% or 
110% plus the highest approved Planning Reserve Margin), which the Commission found 
just and reasonable.  Transmittal at 55-56 (citing Sw. Power Pool, Inc., 194 FERC ¶ 61,031, 
at P 66 (2026)). 
47 Proposed Tariff, attach. DD, § 18.5 (0.0.0), § 18.5(e). 
48 Transmittal at 57, 80-81, 126, 130; Proposed Tariff, attach. DD, § 18.6 (0.0.0), 
§ 18.6(a).  The only exception to this general rule is that if an RBP Resource has an RBP 
commitment beginning with the 2029/2030 delivery year and is not the subject of a notice 
of intent to be offered into the BRA for the 2029/2030 delivery year, such RBP Resource 
would be required to be offered into the Second Incremental Auction for the 2029/2030 
delivery year.  Proposed Tariff, attach. DD, § 5.5 (Eligibility for Participation in RPM) 
(7.0.0), § 5.5(b).  PJM states that this exception is necessary because a Planned 
Generation Capacity Resource that is not the subject of a notice of intent to offer would 
not have been included in the planning parameters for the 2029/2030 BRA.  Transmittal 
at 57.  PJM also proposes Tariff changes to its must-offer exceptions so that an RBP

Docket Nos. ER26-3380-000 and EL26-108-000 
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in the RPM are paid RPM Auction Credits in accordance with RPM rules, and then are 
settled based on the contract-for-difference design for the RBP UCAP MW.49  All load 
that is allocated RBP Charges and participates in the RPM will likewise be charged RPM 
Charges and be charged or receive RBP Charges, based on the contract-for-difference 
settlement.  PJM states that RBP Credits and Charges are only assessed to the extent that 
RBP UCAP MW are committed in the RPM and physically available for dispatch in the 
relevant delivery year.50
ii.
Responsive Pleadings 
The Market Monitor is critical of several aspects of PJM’s proposed eligibility 
requirements for RBP Resources.  To begin with, the Market Monitor faults PJM’s 
proposal for not matching the duration of supply with the duration of data center demand, 
which is 8,760 hours per year.51  The Market Monitor argues that because a four-hour 
battery is eligible to be an RBP Resource, there is a significant mismatch between the 
supply of energy from the battery and the demand for energy from data centers, plus the 
charging demand of the battery.  The Market Monitor states that the same issue exists for 
standalone solar resources.  According to the Market Monitor, the result of this mismatch 
will be higher energy prices for all PJM customers because PJM will need to dispatch 
higher-cost resources to meet energy demand. 
The Market Monitor maintains that permitting Demand Resources and DER 
Capacity Aggregation Resources to serve as RBP Resources creates capacity that is 
materially inferior to Generation Capacity Resources.52  The Market Monitor states that 
committed generation is required to participate in PJM’s day-ahead energy market and 
make itself available for economic dispatch.  In contrast, the Market Monitor asserts, 
committed Demand Resources are only available when PJM invokes emergency 
procedures.  The Market Monitor argues that this is analogous to permitting RBP offset 
capacity to classify its committed ICAP as maximum emergency, requiring PJM to 
invoke emergency procedures to access its reliability benefit. 
Resource cannot avoid the must-offer requirement by exporting its capacity or removing 
its capacity resource status.  Id. at 57-60. 
49 Proposed Tariff, attach. DD, § 18.5 (0.0.0), § 18.5(g). 
50 Transmittal at 81. 
51 Market Monitor Protest at 18-19. 
52 Id. at 22.

Docket Nos. ER26-3380-000 and EL26-108-000 
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The Market Monitor contends that PJM’s proposed qualifying criteria for RBP 
Resources include uprates, Demand Resources, and DER Aggregation Resources—even 
though the goal of the RBP should be to support new generation and to prevent gaming of 
the rules by reclassifying existing capacity resources as new.53  The Market Monitor 
argues that the definition should instead ensure that all cleared capacity represents 
investment in new physical supply rather than redefining existing resources. 
AEU, on the other hand, argues that proposed eligibility rules for Demand Resources 
and DER Aggregation Resources present unnecessary barriers to entry.54  For example, 
AEU notes that, under the proposal, every site backing a commitment must be locked in 
before the resource can bid, for a term length that few demand-side commercial agreements 
can support. 
JCA argues that PJM’s proposal to accept only commitment terms that terminate 
in the 2042/2043 delivery year excludes resources that can energize in time for the 
2028/2029 delivery year but are unwilling or unable to be bound through the 2042/2043 
delivery year.  JCA notes that the Charles River Associates Survey Results showed that 
21% of responding suppliers would agree to terms of 10 years or less.55  JCA asserts that 
PJM’s only support for the 15-year payout period is that it is needed to comply with the 
NEDC/PJM Governors’ Principles.  JCA contends that it is also unduly discriminatory to 
require some ratepayers to pay for 15-year procurements when other ratepayers are 
insulated from RBP Charges due to offset capacity with terms of only five years.56
According to JCA, PJM’s assertion that a five-year contract is sufficient to satisfy the 
RBP’s short-term reliability need cannot be squared with a proposal requiring 15-year 
commitments to meet the same need. 
53 Id. at 20.  The Market Monitor notes that PJM’s criteria in proposed Tariff, 
Attachment DD, Section 18.5(b), uses the capitalized term Installed Capacity, but there is 
no proposed definition or definition in the existing Tariff. 
54 AEU Comments at 18-22; see also NJBPU Comments at 4-5 (advocating for 
more flexibility for the participation of Demand Resources and DER Aggregation 
Resources).  AEU also argues that PJM’s proposal contains unnecessary barriers to 
participation for Surplus Interconnection Service resources.  AEU suggests several 
“opportunities to enhance the RBP” but also states that PJM’s proposal is “good enough” 
if any of the suggestions would delay the RBP.  AEU Comments at 5.   
55 JCA Protest at 14 (citing Charles River Associates Survey Results at 5). 
56 Id. at 17, 34.

Docket Nos. ER26-3380-000 and EL26-108-000 
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In response, PJM argues bilateral arrangements for new capacity are 
distinguishable from the RBP procurement mechanism.57  PJM contends that parties 
entering into bilateral arrangements are not similarly situated to either the suppliers 
offering into the RBP or the LSEs that are allocated cost responsibility for RBP UCAP 
MW, as bilateral arrangements are privately negotiated business deals.  PJM states that 
because bilateral arrangements remain the preferred approach to meeting the resource 
adequacy shortfall, establishing less stringent terms for offset capacity encourages parties 
to 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.  PJM states that it intends the 15-year term to motivate 
supply to participate in meeting the procurement shortfall in a timely manner where other 
measures have failed.   
Parties take various stances on PJM’s proposal to require RBP Sell Offers to 
include the quantity of UCAP to be provided for each delivery year where the maximum 
UCAP included is limited to no greater than 120% of the resource type’s most recent 
maximum Preliminary ELCC Class Ratings for 2028/2029 delivery year through the last 
posted delivery year or based on the resource’s maximum estimated unit-specific ELCC 
ratings across such period for resources with no ELCC Class Rating, multiplied by the 
resource’s ICAP.  AEU asserts that PJM’s proposal unreasonably places “unhedgeable 
ELCC risk” on suppliers and advocates that the risk be shifted to the RPM Auctions, 
which would lower RBP bids.58  Equinix, on the other hand, supports PJM’s proposal, 
arguing that load contracting today cannot price accreditation risk 15 years forward, and 
that a floating credit would transfer to load a modeling risk it has no ability to manage.59
The Market Monitor argues that the proposed ELCC-related rules would permit 
generators to sell more capacity than they have and to do so without penalty for 
overstating capacity.  The Market Monitor argues that allowing RBP Sell Offer UCAP 
MW values up to 120% of the maximum preliminary ELCC class rating for 2028/2029 
through the last posted delivery year will overstate the RBP cleared MW and “require 
customers to pay for nonexistent capacity.”60
Constellation, NRG, and Policy Integrity argue that PJM’s proposal to require 
RBP Resources to offer into the RPM Auctions as price-takers will likely suppress RPM 
57 PJM Answer at 32-36. 
58 AEU Comments at 8-9. 
59 Equinix Comments at 13. 
60 Market Monitor Protest at 14.

Docket Nos. ER26-3380-000 and EL26-108-000 
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prices, leading to premature generator retirements and artificial shortages.61
Constellation asserts that these price-formation and reliability risks are most acute when 
RBP Resources enter the RPM Auctions before the associated demand materializes, even 
if that demand eventually materializes.  In response, PJM asserts that 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.62  PJM argues that the 
Commission has consistently found that the interest in avoiding double-payment 
outweighs the concern of potential price distortion or price suppression.63  PJM contends 
that Constellation and NRG’s positions effectively recycle arguments previously made 
with respect to reliability-must-run resources that have been consistently and summarily 
dispatched by the Commission.  PJM also argues that RBP Resources should not be 
excluded from capacity auctions because it could artificially inflate RPM clearing prices 
or require loads to be double charged for capacity.64  In response, P3 asserts that 
reliability-must-run contracts are localized, short-term measures and therefore are 
61 Constellation Protest at 5-10; NRG Protest at 4; Policy Integrity Comments 
at 11.  See also P3 Answer at 2, 5, 6-7. 
62 PJM Answer at 47 (citing PJM Interconnection, L.L.C., 190 FERC ¶ 61,088,    
at P 50 (2025) (rejecting, inter alia, Constellation’s arguments against offering reliability-
must-run 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); N.Y. Indep. Sys. Operator, Inc.,          
161 FERC ¶ 61,189 (2017), order on reh’g, 163 FERC ¶ 61,047 (2018)). 
63 Id. at 48 (citing 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.”) (citation omitted)); 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”). 
64 Id. at 49-50.

Docket Nos. ER26-3380-000 and EL26-108-000 
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fundamentally distinct from RBP capacity which involves long-term multi-gigawatt     
new generation.65  P3 avers that applying this to RBP will expand a limited construct, 
compounding market disruption and undermining market efficiency and resource 
adequacy across PJM.66  P3 and Constellation argue that PJM does not consider the 
context of the Commission’s decision to require reliability-must-run units to participate 
as price-takers, including that it was time-limited to two auctions to avoid sustained 
disruption to the market.67  P3 requests that the Commission modify PJM’s proposal, 
defer action on this matter to a future proceeding, or establish a paper hearing.68
NRG argues that the Commission should impose a price floor on offers to   
prevent price distortion in the event the expected load does not materialize.  In response, 
PJM argues that there will be a price floor that will apply to all resources offering into the 
RPM through the 2029/2030 delivery year and that a further extension of the price floor 
would be an impermissible attempt to expand the Minimum Offer Price Rule.69
Constellation contests PJM’s proposal to exclude from the RBP an existing 
Energy Resource that has no CIRs but is seeking new CIRs through an Interconnection 
Request, even if the resource otherwise satisfies the RBP eligibility criteria.70
Constellation explains that an existing Energy Resource necessarily has an existing 
Maximum Facility Output—not a “new Maximum Facility Output,” as required by PJM’s 
proposed eligibility rules—and obtaining new CIRs does not create a new Maximum 
Facility Output.  Constellation asserts that the relevant attribute from a resource adequacy 
perspective is the new CIRs.  Constellation concludes that excluding an otherwise 
eligible resource because its Maximum Facility Output is not “new” and because it is 
currently not a capacity resource but is seeking to obtain new CIRs is unjust and 
unreasonable.  In response, PJM argues that the requirement that generation RBP 
Resources have a new Maximum Facility Output and new CIRs ensures that eligible 
resources meet stringent standards before receiving 15 years of price certainty.71
65 P3 Answer at 3-4.  See also Constellation September 21 Answer at 6-7. 
66 P3 Answer at 5.  
67 P3 Answer at 5-6; Constellation September 21 Answer at 5-8. 
68 P3 Answer at 7-8. 
69 NRG Protest at 4, 10; PJM Answer at 51-52. 
70 Constellation Protest at 13-14. 
71 PJM Answer at 41.

Docket Nos. ER26-3380-000 and EL26-108-000 
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PJM states that it has identified a typographical error in proposed Tariff, 
Attachment DD, section 18.5(d).72  PJM states that the section erroneously requires   
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 states, 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 requests that the Commission permit PJM, on compliance, to revise the 
proposed Tariff language to replace the reference to section 18.5(b) with section 18.5(a). 
iii.
Determination 
As a general matter, we find that PJM has demonstrated that its proposed 
eligibility requirements for RBP Resources are just and reasonable.  Specifically, we 
agree with PJM that its proposed eligibility requirements will limit RBP Resources to 
those resources that have demonstrated a high likelihood of success in reaching 
commercial operation and remaining available throughout the RBP commitment period, 
while not being so restrictive as to foreclose significant auction participation.  We further 
find that the stringency of the eligibility requirements for RBP Resources is reasonable 
given the revenue certainty that they will obtain over the RBP commitment period should 
they clear the RBP auction.   
We disagree with the Market Monitor that PJM should have attempted to match 
the duration of supply with the duration of data center demand.  The same energy must-
offer requirements apply to RBP Resources based on their resource type as would apply 
to any other resource of that type that cleared the RPM Auctions.  Similarly, we disagree 
with the Market Monitor’s arguments that uprates, Demand Resources, and DER 
Aggregation Resources should not be eligible RBP Resources.  The Commission has 
dismissed similar arguments from the Market Monitor in the context of the RPM.73
We acknowledge AEU’s concern that few Demand Resources and DER 
Aggregation Resources can lock in their customers for 15 years, as PJM’s proposal  
would require for them to qualify as RBP Resources.  We find, however, that PJM’s 
proposal is nonetheless reasonable.  As PJM explains, in return for the revenue certainty 
that participating in the RBP auction will provide, it is reasonable to expect these 
72 Id. at 46. 
73 See, e.g., Indep. Mkt. Monitor for PJM vs. PJM Interconnection, L.L.C.,         
155 FERC ¶ 61,059, at P 29 (2016) (disagreeing with the Market Monitor’s argument 
that a day-ahead energy market must-offer requirement must be imposed on capacity 
demand response resources to treat them on a fully comparable basis relative to 
generation capacity resources).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 20 - 
resources to be available during the entire RBP commitment period.74  Like any other 
resource type, Demand Resources and DER Aggregation Resources that cannot commit 
themselves through the 2042/2043 delivery year are not eligible to participate in the RBP 
as RBP Resources, but—as is the case today—they continue to have the opportunity to 
participate in PJM’s routine RPM Auctions.  We also disagree with JCA that PJM cannot 
reasonably propose to terminate all RBP Resource commitment terms in the 2042/2043 
delivery year and should instead allow for shorter commitment terms.  We note that this 
requirement aligns with PJM’s proposed clearing mechanism, described below, which we 
find to be just and reasonable. 
We are unpersuaded by Constellation’s argument that PJM’s proposal to exclude 
generation resources that could provide new CIRs, but no new installed capacity, is 
unjust and unreasonable.  On the contrary, we agree with PJM that the RBP price 
certainty of up to 15 years should be used to attract both new installed capacity and new 
CIRs.   
We find just and reasonable PJM’s proposal to require RBP Sell Offers to include 
the quantity of UCAP to be provided for each delivery year where the maximum UCAP 
included is limited to no greater than 120% of the resource type’s most recent maximum 
Preliminary ELCC Class Ratings for 2028/2029 delivery year through the last posted 
delivery year or based on the resource’s maximum estimated unit-specific ELCC ratings 
across such period for resources with no ELCC Class Rating, multiplied by the resource’s 
ICAP.  We agree with PJM that the proposed cap represents a reasonable balance 
between providing sellers with flexibility and managing UCAP risk for load.  Under 
PJM’s proposal, load pays for only RBP capacity delivered.75  Thus, the only risk is that 
PJM procures 20% more capacity on paper than what eventually materializes.  We are 
not persuaded that such potential harm renders this component of PJM’s proposal unjust 
and unreasonable.  Instead, we find an actual procurement that may result in up to 20% 
less capacity than the estimated target to be acceptable in the context of an estimated 
74 Transmittal at 52 (“Recognizing that RBP Resources will have longer-term 
commitments and price certainty . . . PJM is proposing comparatively more restrictive 
criteria for participating resources to help ensure that resources participating in the RBP 
are limited to those that have demonstrated a high likelihood of success in reaching 
commercial operation in the near term and remaining available throughout the 
commitment period.”); PJM Answer at 44 (“The [15-year contract] requirement 
ultimately provides PJM confidence that DR/DER serving as RBP Resources will 
actually be available for the term of the RBP commitment.”). 
75 Proposed Tariff, attach. DD, § 18.5(g)(i).

Docket Nos. ER26-3380-000 and EL26-108-000 
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resource adequacy shortfall of 6,831 MW, particularly as compared to the total MW of 
capacity that cleared in PJM’s 2028/2029 BRA.  
We also disagree with arguments against PJM’s proposal to require RBP 
Resources to offer into the RPM Auctions as price-takers because the requirement        
will likely suppress RPM prices, leading to premature generator retirements and    
artificial shortages.  As PJM notes, the Commission has consistently found that   
Regional Transmission Organizations and Independent System Operators can reasonably 
require resources that are compensated outside of the capacity market because they are 
needed to maintain reliability to offer as price-takers in capacity auctions to avoid double 
procurement, even at the risk of price suppression.76  Here, where PJM is proposing to 
procure RBP Resources outside of its routine RPM Auctions because those auctions have 
failed to secure sufficient capacity to meet the PJM Region’s reliability requirements, we 
find that it is likewise just and reasonable to require RBP Resources to offer into PJM’s 
RPM Auctions as price-takers to avoid the risk of over-procuring capacity through those 
auctions. 
Finally, we acknowledge PJM’s request that the Commission exercise its discretion 
to correct a typographical error in proposed Tariff, Attachment DD, section 18.5(d).  If 
PJM were to choose to expeditiously submit an FPA section 205 filing, PJM may decide 
whether to include that proposed revision.  
b.
Average-Price Cap and Clearing Mechanism 
i.
Filing 
PJM proposes that the levelized procurement cost of all selected RBP Sell Offers 
not exceed a maximum willingness to pay of $555/MW-day, on a MW-weighted average 
basis over all delivery years of the RBP.77  PJM notes that earlier this year the 
Commission accepted a price cap of $555/MW-day for the 2028/2029 BRA, and that but 
76 PJM Interconnection, L.L.C., 196 FERC ¶ 61,098, at P 21 (2026) (finding     
that PJM’s proposal to include reliability-must-run units in the RPM supply stack            
as price-takers is just and reasonable and consistent with Commission precedent 
regarding the treatment of reliability-must-run resources in other regions) (citing PJM 
Interconnection, L.L.C., 193 FERC ¶ 61,234, at P 10 (2025) (citing PJM Interconnection, 
L.L.C., 190 FERC ¶ 61,088, at P 50 (2025) (citing Indep. Power Producers of N.Y., Inc. 
v. N.Y. Indep. Sys. Operator, Inc., 150 FERC ¶ 61,214 (2015); N.Y. Indep. Sys. Operator, 
Inc., 150 FERC ¶ 61,116 (2015), order on reh’g & compliance, 155 FERC ¶ 61,076 
(2016), order on reh’g & compliance, 161 FERC ¶ 61,189 (2017); ISO New Eng. Inc., 
165 FERC ¶ 61,202 (2018)))). 
77 Transmittal at 61.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 22 - 
for the lower temporary price cap, the BRA would have cleared at this cap.78  PJM 
explains that, given that the Initial RBP Target is based on the 2028/2029 BRA shortfall, 
PJM proposes $555/MW-day as the cap to what load will pay for RBP capacity.  PJM 
argues that this “budget approach” allows the RBP to manage costs while not restricting 
Sell Offers to a hard price cap, and allows for potentially fluctuating offers across the     
15 delivery years of the RBP term. 
PJM argues that the proposed maximum willingness to pay balances the need to 
procure capacity and maintain system reliability—recognizing that prices above the 
$555/MW-day cap in some delivery years may nevertheless be appropriate under scarcity 
conditions—with consumer protection considerations by requiring that, ultimately, the 
average procurement price not exceed $555/MW-day over the RBP term.  PJM further 
argues that a MW-weighted average provides sellers flexibility not offered by hard caps 
on RBP Sell Offers.  PJM argues that setting a maximum is necessary because the RBP is 
not disciplined by direct buy bids that explicitly express willingness to pay, and it is not 
reasonable to assume that load should be obligated to pay an unlimited amount for 
supply.  PJM argues that it is reasonable to conclude that PJM’s willingness to pay for a 
15-year commitment should not exceed the amount that load would be willing to pay for 
a single-year commitment under the RPM framework, given the benefits to supply 
resources of revenue certainty and the chance to reduce financial and development risk 
and improve financing opportunities through lower capital costs or more favorable 
financing terms.79
PJM proposes to commit RBP Resources using a pay-as-bid approach, which PJM 
argues is more appropriate for a one-time backstop procurement than the single-clearing-
price approach used in the RPM.80  First, PJM argues that because the RBP is a one-time 
procurement, its pricing outcomes are less likely to serve as market signals.  Second, PJM 
notes that the RBP will not be procuring a uniform commodity because resources may 
differ based on commercial operation dates, Network Upgrades, and other factors.  Third, 
PJM states that a uniform clearing price would require PJM to normalize offers through 
potentially complex and subjective assumptions. 
78 Id. at 62 (citing PJM Interconnection, L.L.C., 194 FERC ¶ 61,049, at PP 44-45, 
order on reh’g, 196 FERC ¶ 61,007 (2026)). 
79 Id. at 63-64. 
80 Id. at 65.  PJM states that the Commission has previously found it just and 
reasonable to pair a pay-as-bid approach to backstop procurement with a maximum 
willingness to pay.  Id. (citing Cal. Indep. Sys. Operator Corp., 153 FERC ¶ 61,001 
(2015)).

Docket Nos. ER26-3380-000 and EL26-108-000 
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For RBP Resources to clear the auction, PJM proposes to first filter prospective 
resources through “gating” criteria, which PJM argues will ensure that the selected RBP 
Resources are those most likely to go into service and will deter speculation.81  For 
generation and storage resources, the seller must provide:  (1) a critical path construction 
schedule supporting the feasibility of a commercial operation date of June 1, 2032, or 
earlier; (2) interconnection study information and a development timeline appropriate to 
its interconnection queue study process; (3) evidence of 100% site control; (4) a financing 
plan showing that the resource has sufficient financial backing; (5) a permitting plan 
showing that the developer is on track to obtain all necessary permits; and (6) evidence 
that the developer has or will procure the necessary major equipment.  In addition, the 
seller must demonstrate that it is able to develop the underlying resource by providing 
“[e]vidence of experience having constructed a previous project of similar size and 
technology or have contracted with an engineering, procurement, and construction partner 
with such experience.”82  A seller offering RBP UCAP MW based on a natural-gas-fired 
resource must provide evidence of a delivering pipeline.  To the extent the resource is 
located outside the PJM Region, the seller must demonstrate that the resource has 
progressed through its host region’s interconnection study process to obtain a completed 
facilities study or the equivalent and, consistent with PJM’s pseudo-tie requirements, a 
long-term firm point-to-point transmission service, or a confirmed transmission service 
request with a completed system impact study, sufficient to deliver capacity to PJM’s 
border. 
For Demand Resources and DER Capacity Aggregation Resources, the seller  
must provide evidence of the locations within PJM of the load reduction and executed 
customer agreements or binding commitments with identified locations and customer 
names sufficient to cover the offered MW quantity.83  The seller must also show that it 
will be able to effectuate the offered load reduction through evidence of an “[e]quipment 
procurement plan or evidence of deployed enabling infrastructure such as metering, 
telemetry, load control, [Supervisory Control and Data Acquisition]/dispatch systems, or 
DER major equipment as applicable.”84
After applying the gating criteria, PJM evaluates the RBP Sell Offers based on the 
first delivery year offered in the RBP Sell Offer, levelized cost, and RBP UCAP MW 
quantity.  The proposed selection process first orders all Sell Offers based on the 
81 Id. at 71.  PJM also notes that it will give sellers an opportunity to cure any 
PJM-identified deficiencies.  Id. at 72. 
82 Id. at 73 (quoting Proposed Tariff, attach. DD, § 18.5(f)(i)(6)). 
83 Id. at 74. 
84 Id. at 75 (quoting Proposed Tariff, attach. DD, § 18.5(f)(i)(11)).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 24 - 
resource’s identified offered delivery year, and then by price, by ordering the RBP Sell 
Offers “in least-cost order based on the levelized cost ($/MW-day) of UCAP MW over 
the fixed 15-year term.”85  From this stack of offers, PJM proposes to select RBP Sell 
Offers until the Final RBP Target is satisfied.  PJM explains that because all RBP 
commitments terminate with the 2042/2043 delivery year regardless of which delivery 
year the RBP Resource first offered, the levelized cost determination is needed for a 
comparative evaluation for each resource for the period between commercial operation 
and the 2042/2043 delivery year.  PJM explains that a levelized cost accounts for the time 
value of money, which is critical when evaluating contracts spanning 15-year terms, as 
PJM is proposing in the RBP.  PJM explains that levelized cost will be calculated as:  
Levelized Cost ($/MW-day) = Net Present Value (RBP Sell Offer price * UCAP 
offered)/Net Present Value (UCAP offered), with a discount rate equal to 9.5% after-tax 
average weighted average cost of capital.86
PJM explains that, in selecting resources from the offer stack, it will first look to 
RBP Resources expected to reach commercial operation in the 2028/2029 delivery year.  
If that set of resources is insufficient to meet the Final RBP Target, then PJM will apply 
the selection criteria to consider all resources offered with an expected commercial 
operation date in the 2029/2030 delivery year, and will continue iteratively, up to          
and including the 2032/2033 delivery year, until the set of offers selected meets the    
Final RBP Target.  PJM further explains that, within this selection process, it will not 
procure a resource that results in the MW-weighted average of the levelized procurement 
cost exceeding $555/MW-day, meaning that it may skip over a resource with an earlier 
delivery year if procuring that resource would violate the maximum willingness to pay 
for the procurement.87  If a resource is skipped because it violates the cap but a lower-
cost resource is procured that then creates “room in the budget” to select that higher-
offer-earlier delivery year resource, the selection process will go back to procure that 
resource before continuing down the rank-order of additional offers in later delivery 
years.  PJM explains that the selection process prioritizes earlier delivery years to address 
the shortfall target as soon as possible.  PJM also states that, in procuring the least-cost 
set of resources, it may clear an RBP Sell Offer with an offered quantity that exceeds the 
remaining Final RBP Target if the solution results in a lower overall cost than the 
alternative.88  That is, PJM may exercise the option to procure more capacity than the 
Final RBP Target if, compared to acquiring a resource with a higher offer price that 
85 Id. (quoting Proposed Tariff, attach. DD, § 18.5(f)(ii)). 
86 Id. at 76-77. 
87 Id. at 78. 
88 Id. at 79.

Docket Nos. ER26-3380-000 and EL26-108-000 
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would not reach the Final RBP Target, PJM would end up paying less overall.  PJM 
asserts that this would result in the more economical outcome.  Relatedly, PJM notes   
that because the RBP is procuring new capacity and not simply fungible UCAP MW, 
RBP Resources shall not be partially cleared.  Thus, PJM may clear a set of resources 
with a cumulative RBP UCAP MW total that does not exactly match the Final RBP 
Target. 
Finally, PJM states that, following the conclusion of the RBP and to the extent 
consistent with the existing member confidentiality rules, PJM will post a report that, 
inter alia, provides a transparent overview of the aggregate MW that were procured 
through the RBP and a weighted average of the RBP Charges as soon as is practicable 
after the RBP is completed.89
ii.
Responsive Pleadings 
JCA argues that RBP’s design defeats itself by requiring the purchase of long-term 
resources while constraining the participation of shorter-term resources that could better 
align with the identified need, and that PJM has not defended the 15-year commitment 
term as necessary to cure the reliability shortfall.  JCA asserts that it is unjust and 
unreasonable to charge ratepayers for the acquisition of years of capacity that is not 
needed to address the reliability shortfall and serves no cost-efficiency or other economic 
purpose.90
Several intervenors argue that the $555/MW-day cap is too high.  JCA argues    
that the $555/MW-day cap should be substantially less because 15-year price certainty 
reduces supplier risk and eases financing.91  JCA also argues that ratepayers could pay 
more than $555/MW-day if any resource that bid less fails to materialize or ceases 
operation prior to the end of the RBP term.  JCA argues that PJM’s borrowing of Point 1 
from the VRR curve is inapposite because it is a reference cost grounded in the estimated 
Cost of New Entry (CONE) for a combustion turbine (CT) reference resource, whereas 
the RBP has no reference resource or VRR curve.  OCC argues that the proposed cap is 
significantly higher than the clearing price in the 2028/2029 BRA of $325/MW-day at the 
89 Id.
90 JCA Protest at 16 (citing Citadel FNGE Ltd. v. FERC, 77 F.4th 842, 856      
(D.C. Cir. 2023) (explaining that the “application of [a PJM auction rule] was unjust and 
unreasonable not just because of how much it increased the wholesale rate, but because it 
caused that increase for no justifiable purpose” and “without any commensurate 
[consumer] benefit”)). 
91 Id. at 25.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 26 - 
price cap, which also reflects the scarcity conditions in that auction.92  The Market 
Monitor states that net revenues in the energy market are significantly higher now than 
they were when PJM calculated the $555/MW-day figure.  Therefore, the Market 
Monitor argues, PJM has significantly overstated the maximum price for the RBP.93
Other intervenors, however, argue the $555/MW-day cap is too low.  E-Cubed 
asserts that PJM’s proposed average price cap is not just and reasonable because it is not 
reflective of actual costs, nor will it solve the identified capacity shortfall.  E-Cubed 
argues that, based on its analysis of publicly available data, it is unlikely that any capacity 
will be committed via RBP because the $555/MW-day volume weighted average 
constraint on purchases in the RBP is not commensurate with the actual cost of bringing 
capacity into PJM for any resource type.94  NRG argues that there should be no price cap 
because the top priority should be allowing the RBP to fulfill its purpose of covering the 
capacity shortfall.  According to NRG, even if a price cap were appropriate, PJM has not 
explained why a soft cap based on an outdated estimate of CONE for a CT in the last 
quadrennial review is a just and reasonable level.  NRG further states that capital costs 
have escalated sharply since that estimate was calculated.  NRG argues that there is no 
logical reason why the prices paid to individual suppliers in the RBP should be subject to 
a cap based on CONE for a CT when the capacity shortfall could be covered with any 
number of resources, including resources using different technologies or having other 
characteristics that cause their costs to significantly exceed those of the reference CT.  
NRG states that it has a project sufficiently advanced to participate in the RBP that has 
costs, net of expected energy and ancillary services revenues, that are substantially 
greater than the $555/MW-day cap, and it would be hard to justify the time and expense 
of offering it into the RBP given its costs and size.  NRG argues that if the Commission 
does not eliminate the soft cap entirely, it should reset the cap to $866/MW-day.95
OELC argues that the proposed RBP Resource selection method is not just and 
reasonable because it does not adequately incentivize new dispatchable generation, which 
is most capable of serving load during the reliability risk conditions for which the RBP is 
designed.  OELC urges the Commission to modify PJM’s proposed resource-selection 
method to value new dispatchable generation’s reliability attributes.96
92 OCC Protest at 8. 
93 Market Monitor Protest at 27. 
94 E-Cubed Protest at 2, 6, 19. 
95 NRG Limited Protest at 5-10. 
96 OELC Comments at 2, 9-10.  See also FirstEnergy Protest at 15-17.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 27 - 
Voltus argues that the proposed gating criteria for RBP Resource offers do not 
recognize the commercial development pathways of distributed demand-side resources.  
Voltus notes that, under PJM’s proposal, Demand Resource and DER Capacity 
Aggregation offers must “[i]dentify, as part of its RBP Sell Offer, for the full length of 
the fixed term, the location(s) and associated participation contract(s)” and will only be 
considered if they include “[e]xecuted customer agreements or binding commitments 
covering the proposed RBP UCAP MW commitment, with identified locations, customer 
names, and expected curtailment/injection capability per site.”97  Voltus argues that this 
gating criterion inverts the development sequence because customer contracts are entered 
into against a known price and volume (i.e., the output of the auction).  According to 
Voltus, requiring customer contracts before the auction removes the commercial basis on 
which they would be executed.  Relatedly, AEU requests that PJM “confirm . . . that a 
procurement plan, rather than infrastructure already installed and operational at the time 
of the offer, is sufficient to satisfy” the gating criteria for Demand Resources and DER 
Capacity Aggregation Resources.98  On the other hand, FirstEnergy argues that the gating 
criteria for demand response contain a significant ambiguity, requiring only a contract or 
agreement evidencing a “plan or evidence of deployed enabling infrastructure,” not one 
demonstrating a clear and binding commitment to provide the MWs sold into the RBP.99
FirstEnergy argues that the language risks treating speculative resources as equivalent to 
committed resources.  FirstEnergy thus requests that PJM clarify that eligible demand 
response resources must be supported by binding contractual commitments. 
The Market Monitor argues that the RBP clearing process is not consistent with 
cost minimizing principles because it favors resources with a commercial operation date 
in 2028/2029 over resources with later commercial operation dates even when the later 
resources are less costly and have better reliability characteristics.100  Some parties       
also fault PJM’s proposed pay-as-bid structure because, as PJM concedes, sellers in a 
pay-as-bid auction bid the expected clearing price, not their marginal costs.101
CPV supports the proposal but argues that the gating criteria language requires 
clarification to avoid inadvertently narrowing the pool of eligible projects.  CPV notes 
97 Voltus Protest at 3, 10-15 (citing Proposed Tariff, attach. DD, §§ 18.5(c)(ii), 
18.5(d)(i), 18.5(f)(i)(10)).  See also NJBPU Comments at 4-5. 
98 AEU Comments at 21. 
99 FirstEnergy Protest at 21 (citing Transmittal at 74-75). 
100 Market Monitor Protest at 24-25. 
101 JCA Protest at 6; Market Monitor Protest at 11-13; NJBPU Comments at 4; 
OCC Protest at 7-8.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 28 - 
that the gating criteria require sellers to demonstrate site control for a term of at least 
three years from the date of submission of an “Application,” but that the Tariff’s    
existing definition of “Application” has no connection to the RBP.102  CPV proposes       
a correction to refer instead to an “RBP Sell Offer.”  CPV also argues that proposed 
section 18.5(f)(i)(2) fails to account for sellers with generation projects currently active   
in PJM’s interconnection queue that have already satisfied the applicable site control 
requirements that are a condition of advancing through the queue.103  CPV argues that 
requiring such developers to separately satisfy a new three-year requirement on limited 
notice could impose an unnecessary additional burden.  CPV proposes to clarify that 
proposed section 18.5(f)(i)(2) applies only “[f]or projects without an active queue 
position.” 
iii.
PJM Answer 
PJM asserts that the arguments that procuring for a fixed term of up to 15 years is 
unjust and unreasonable are without merit.  PJM argues that the 15-year term for RBP is 
intended to motivate supply to participate in meeting the procurement shortfall in a 
timely manner where other measures have failed.104
Regarding the proposed $555/MW-day price cap, PJM notes that some intervenors 
argue that the cap is too high,105 while others argue that it is too low.  PJM highlights   
that no entity that would ultimately be responsible for paying the RBP Charges raised 
concerns with the proposed level of the cap.  PJM also argues that the fact that some 
intervenors argue that the cap is too high, while others claim that it is too low, is not 
indicative of a flaw in the proposal but rather 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.106  Finally, PJM also argues that the revenue 
certainty of a 15-year term mitigates concerns that costs have risen since the periodic 
review that produced the $555/MW-day figure, and notes that while a handful of 
suppliers argue against the proposed level of the cap, others did not.107
102 CPV Comments at 4. 
103 Id. at 5. 
104 PJM Answer at 32-35. 
105 Id. at 37 (citing OCC Protest at 8; JCA Protest at 25-28; IMM Protest at 27-28). 
106 Id. at 38-39 (citing E-Cubed Protest at 2; NRG Limited Protest at 6, 10). 
107 Id. at 40 (citing, generally, CPV Comments).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 29 - 
PJM responds to concerns that the proposed gating criteria are too stringent by 
arguing that the criteria are appropriately tailored to limit the RBP to new capacity      
with a high likelihood of coming online.108  PJM states that it will provide sellers the 
opportunity to cure PJM-identified deficiencies and anticipates working hand-in-hand 
with capacity resources to determine how deficiencies may be cured.  In response to 
arguments that the gating criteria for Demand Resources and DER Capacity Aggregation 
Resources specifically are overly stringent, PJM states that the difference is by design, 
because generation/storage resources are tied to physical assets that make it costly to exit 
the market early, whereas Demand Resources and DER Capacity Aggregation Resources 
are, by nature, contracts or agreements that are not tied to a dedicated asset.  PJM also 
notes that Demand Resources and DER Capacity Aggregation Resources are able to 
easily enter and exit the market based on economic and other business decisions.  Finally, 
PJM states that RBP is designed to not allow for replacement of RBP Resources so that 
only the RBP Resource is eligible for RBP payments, and requiring evidence that the 
Demand Resource/DER locations are contracted for 15 years ensures parity with 
generation/storage resources that participate in RBP. 
PJM states that it is amenable to CPV’s suggested revision to the gating criteria 
requirement that Generating Facilities provide evidence of 100% site control.  PJM agrees 
that the term “Application” may be ambiguous in the proposed Tariff language requiring 
evidence of 100% site control “for a term of at least three years from the date of 
submission of the Application,”109 and clarifies that the language was intended to state that 
the three-year site control requirement would begin from the date when sellers submit 
their RBP Sell Offer, as CPV suggested.110  Further, PJM states that CPV’s request to 
clarify that such requirement should only be applicable to projects that do not already have 
an active queue position is reasonable, because projects that are both already in the 
interconnection queue and already meet the relevant prerequisites to proceed through      
the queue will have already demonstrated a high likelihood of actualization and success.  
PJM believes that CPV’s suggested redlines to proposed Tariff, Attachment DD,      
section 18.5(f)(i)(2) to this effect are reasonable. 
iv.
Determination 
As a general matter, we find that PJM has shown that its proposed $555/MW-day 
maximum willingness to pay and process for selecting RBP Resources in the RBP 
auction are just and reasonable.  We agree with PJM that a maximum willingness            
to pay set at the MW-weighted average of the levelized procurement cost over the      
108 Id. at 42. 
109 Proposed Tariff, attach. DD, § 18.5(f)(i)(2). 
110 PJM Answer at 44-45 (citing CPV Comments at 4-5).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 30 - 
RBP commitment term reasonably balances the need to expeditiously procure capacity in 
response to the PJM Region’s imminent capacity shortfall with ensuring that the average 
procurement price does not exceed load’s maximum willingness to pay.  We further find 
that in establishing the value for the maximum willingness to pay in the RBP, PJM 
reasonably relied on the value of the RPM price cap that the Commission accepted in 
January and reaffirmed in July.111  We disagree with arguments that the Commission 
must direct PJM to adopt a value for load’s maximum willingness to pay that is based on 
the most recent forward prices and production costs.  Specifically, we find that using the 
$555/MW-day price cap for the 2028/2029 BRA—which was just approved this January 
and affirmed in July, as noted directly above—is a reasonable proxy of load’s maximum 
willingness to pay for RBP capacity.    
We agree with PJM that the proposed pay-as-bid structure for the RBP auction is 
reasonable.112  As PJM explains, the RBP auction is not procuring a uniform product 
because RBP Resources may differ based on commercial operation dates and other 
factors.  As such, we find that it is reasonable for each RBP Resource to be paid the price 
that it bids when offering into the RBP auction.  We recognize that, as both PJM and 
protesters note, sellers are theoretically less likely to offer near their marginal costs in a 
pay-as-bid auction than in a single-price auction.  We find, however, that this theoretical 
drawback is acceptable in the context of the proposed $555/MW-day average-price cap 
and the Charles River Associates Survey Results indicating strong seller interest in the 
RBP auction.113
Moreover, we find that PJM’s proposed gating criteria for RBP Resources are just 
and reasonable.  These criteria, which PJM will employ as the first step in the selection 
process for RBP Resources, will help to deter speculative resources from bidding into the 
RBP auction and ensure that the selected RBP Resources are those most likely to go into 
service.  Regarding arguments that Demand Resources and DER Capacity Aggregation 
Resources cannot feasibly lock in their customers for 15 years before the RBP auction, 
we find that PJM has justified this requirement as reasonable.  Specifically, PJM explains 
that this restriction is necessary to manage the risk of the supply being available for the 
full term that PJM is procuring on behalf of load in the RBP.114  Failing to require 
Demand Resources and DER Capacity Aggregation Resources to provide evidence of the 
111 PJM Interconnection, L.L.C., 194 FERC ¶ 61,049, at PP 45-46, 49 (2026), 
order on reh’g, 196 FERC ¶ 61,007, at PP 25-26. 
112 We note that the existing Reliability Backstop Auction also uses a pay-as-bid 
structure.  Tariff, attach. DD, § 16 (2.0.0), § 16.4(e)(2). 
113 Charles River Associates Survey Results at 5. 
114 PJM Answer at 54.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 31 - 
executed customer agreements or binding commitments with identified locations and 
customer names sufficient to cover the offered MW quantity could result in such 
resources contracting with different loads over the life of the RBP commitment term, 
contrary to its purpose of providing long-term revenue certainty for RBP Resources.  
Additionally, we disagree with JCA that PJM unreasonably requires commitment terms 
ending no earlier than 2042/2043.  As PJM explains, long contract terms create revenue 
certainty for RBP Resources and generally can reduce financial and development risk and 
may improve financing opportunities through lower capital costs or more favorable 
financing terms.115
PJM explains that, after applying the gating criteria, it would evaluate sell offers 
first based on the resource’s identified offered delivery year, then by price, until the   
Final RBP Target is satisfied.  We agree with PJM that this process for selecting RBP 
Resources in the RBP auction reasonably prioritizes earlier delivery years to address the 
PJM Region’s capacity shortfall as soon as possible.  We disagree with OELC that PJM’s 
proposed process for selecting RBP Resources in the RBP auction is deficient because it 
does not value dispatchable generation’s reliability attributes beyond what PJM’s ELCC 
accreditation already captures because we do not find such additional valuation metrics to 
be necessary for PJM’s proposal to be just and reasonable. 
Finally, we acknowledge PJM’s openness to adopt CPV’s suggested redlines to 
proposed Tariff, Attachment DD, section 18.5(f)(i)(2).  If PJM were to choose to 
expeditiously submit an FPA section 205 filing, PJM may decide whether to include 
those revisions.   
c.
RBP UCAP MW Shortfall Charges  
i.
Filing 
PJM proposes that an RBP UCAP MW shortfall will occur when a committed 
RBP Resource has not reached commercial operation for the relevant delivery year for up 
to three consecutive years unless the RBP Resource qualifies for an exception because it 
is waiting on Network Upgrades.116  Once an RBP Resource has achieved commercial 
operation, PJM proposes that RBP UCAP MW shortfall charges will end but that RBP 
Resources are not paid for any RBP UCAP MW not provided.  PJM proposes that RBP 
115 Transmittal at 63-64. 
116 Proposed Tariff, attach. DD, 18.6 (0.0.0), § 18.6(d)(i) (“An RBP Resource    
that is a generation or Energy Storage Resource and is unable to meet [its] expected 
commercial operation date solely due to Network Upgrades shall be excepted from RBP 
shortfall charges if the RBP Resource successfully demonstrates readiness through test 
energy and seeks interim deliverability.”).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 32 - 
shortfall charges will be equal to the product of the RBP Resource’s committed RBP 
UCAP MW shortfall and 20% of the RBP price.  If the RBP Resource fails to provide 
any RBP UCAP MW after three consecutive delivery years, PJM proposes that the RBP 
commitment will be rescinded for the remainder of the term.  PJM states that it proposes 
to allow RBP Resources to retain RBP UCAP MW commitments for up to three years 
because a resource’s commercial operation date may be delayed even when a project is 
viable.117  PJM argues that the limitation on RBP shortfall charges helps reduce the 
barrier to entry. 
ii.
Responsive Pleadings 
The Market Monitor contests the proposed RBP UCAP MW shortfall charges, 
arguing PJM inappropriately proposes to shift ELCC-related risk from generators to 
customers because shortfalls due to decreases in the ELCC ratings are not subject to 
penalties.  The Market Monitor argues that generator performance risk is an investor risk 
and not a customer risk, and that one of the benefits of markets is that performance risk is 
assigned to generators because they are responsible for unit performance.  The Market 
Monitor contends that the absence of shortfall charges for failure to deliver the quantity 
of UCAP sold shifts the ELCC accreditation risk to load, which must pay for the 
additional supply to cover the shortfall.118
The Market Monitor also argues that PJM unnecessarily restricts the applicability 
of shortfall charges to a narrow reason, is vague about the timing of the charges, and 
unreasonably limits the charges to three years.119  The Market Monitor adds that PJM’s 
proposed criteria for defining shortfall charges are also vague and unenforceable, and that 
PJM has not explained why the RBP penalties vary so significantly from the current RPM 
rules.  The Market Monitor states that deficiency charges under the current RPM rules are 
assessed due to a failure to satisfy a commitment “for any reason,” such as derates and 
retirements, whereas the proposed shortfall charges would only apply for commercial 
operation delays.  For example, the Market Monitor argues, if a generation project 
configuration and MW change significantly but it still achieves commercial operation by 
the delivery year, it is not clear whether RBP shortfall charges would apply. 
The Market Monitor further argues that use of the term “commercial operation” 
instead of the more precise tariff-defined “commencement of Interconnection Service” 
117 Transmittal at 61. 
118 Market Monitor Protest at 14-15. 
119 Id. at 15.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 33 - 
limits the applicability of RBP UCAP MW shortfall charges even more so.120  Also, the 
Market Monitor states, the term “commercial operation” is generally not a term applied   
to Demand Resources and DER Aggregation Resources, and it is not clear how the 
shortfall charges would apply to these resource types.  The Market Monitor states that in 
defining the eligibility criteria for RBP Resources in proposed Tariff, Attachment DD, 
section 18.5(a)(i), PJM distinguishes Demand Resources and DER Aggregation 
Resources as being registered and under a contract to perform versus having a 
commercial operation date prior to June 1, 2032.  The Market Monitor argues that      
PJM does not explain why this same distinction is not included in the shortfall charge 
provision. 
The Market Monitor also contests PJM’s proposed Shortfall Penalty exception for 
unavailability due to delayed Network Upgrades, arguing that the proposal shifts risks 
from resource owners to load.121
iii.
Determination 
We find that PJM’s proposed RBP UCAP MW shortfall charges are just and 
reasonable because they will deter speculative resources from seeking to participate in  
the RBP auction without creating an undue barrier to entry.  Under PJM’s proposal, an 
RBP UCAP MW shortfall occurs when a committed RBP Resource has not reached 
commercial operation for the relevant delivery year for up to three consecutive years.  
RBP shortfall charges are equal to the product of the RBP Resource’s committed RBP 
UCAP MW shortfall and 20% of the RBP price.  We find that PJM’s proposal to assess 
penalties at this level, for up to three years, is just and reasonable because these penalties, 
along with the pay-as-bid RBP clearing price and the promise of up to 15 years of 
revenue certainty, will incentivize developers of RBP Resources to deliver their RBP 
UCAP MW.     
We disagree with the Market Monitor’s various criticisms of the proposed        
RBP UCAP MW shortfall charges, including the Market Monitor’s argument that PJM 
inappropriately proposes to shift ELCC-related risk from generators to customers.  Under 
the proposal, LSEs pay RBP Charges for only the RBP UCAP MW delivered.  Thus, the 
risk for customers is that they end up paying for less RBP capacity than they anticipated.  
However, PJM’s proposal mitigates this risk because, as discussed above, other aspects 
of the proposal strongly encourage RBP Resources to deliver. 
We also disagree with the Market Monitor’s arguments that PJM’s proposed Tariff 
revisions describing the shortfall charges are impermissibly vague, and that the 
120 Id. at 16. 
121 Id. at 17.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 34 - 
Commission should reject the proposed exception for unavailability due to delayed 
Network Upgrades.  On the contrary, we find that this exception is a reasonable approach 
because it removes a risk over which RBP Resources have no control.  More generally, 
we are not persuaded by the Market Monitor’s multiple comparisons between the 
proposed RBP rules and the existing RPM rules because the RBP is a stopgap measure to 
address the failure of the RPM to attract sufficient supply.  An intervention, almost by 
definition, is not going to be “consistent with PJM’s fundamental market design,” as the 
Market Monitor contends. 
d.
Lack of Locational Constraints and Market Power 
Mitigation 
i.
Filing 
PJM explains that it does not propose to apply locational constraints in the RBP.122
PJM states that just as the driver of the RBP is the resource adequacy shortfall at the PJM 
Region level, the Final RBP Target is based on a regionwide shortfall.  PJM states that 
while it recognizes there are locational considerations at large for resource adequacy,    
and these constraints are modeled in the RPM Auctions, it is also the case that the RPM   
is an annual three-year forward framework, which allows PJM to model the necessary 
locational parameters—Capacity Emergency Transfer Objectives (CETO) and Capacity 
Emergency Transfer Limits (CETL)—to accurately capture the locational needs in the 
capacity market.  By contrast, PJM argues, it does not project and calculate these 
parameters 15 years out, which is the eligible term of the RBP, because PJM does not 
have the information needed to determine such locational parameters for 15-year term 
capacity commitments.  PJM states that as a result, including locational parameters based 
on today’s conditions would inevitably skew the results and lead to either over-
procurement or under-procurement in given zones based on nothing more than 
speculation as to the state of the system 10 and 15 years from now.  Moreover, PJM 
argues that inclusion of a speculative locational parameter at this point would ignore the 
fact that PJM’s interconnection process ensures the initial deliverability of new capacity 
to the region.  PJM also notes that, 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.  PJM states 
that load deliverability is also assessed as part of the RTEP process, which will identify 
transmission needs as load patterns change. 
PJM states that it is also not proposing direct market power screens or mitigation 
for the RBP because, in the context of a pay-as-bid structure with a $555/MW-day cap, 
the effectiveness of such measures would be limited.  PJM notes that a pay-as-bid 
122 Transmittal at 33-34.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 35 - 
structure, unlike a single-clearing-price structure, does not allow any resource to impact 
the clearing price of any other resource.123  In addition, PJM states, its proposed average-
price cap of $555/MW-day further discipline costs by increasing the risk that high offers 
do not clear.  PJM states that PJM’s proposed average-price cap is similar to the existing 
market mitigation rules for Planned Generation Capacity Resources because PJM may 
reject sell offers from those resources if they exceed 140% of an average, relevant 
price.124
PJM argues that the risk of economic withholding is limited, because the suppliers 
can choose whether to participate.125  PJM notes that its maximum procurement target 
under the RBP is limited to the 2028/2029 BRA shortfall of 6,831 MW.  PJM further 
notes that the Charles River Associates Survey Results identified more than 100 GW     
of prospective supply interested in participating in some form through this process.126
PJM argues that this level of interest indicates there is available supply that will compete 
to secure an RBP commitment.  PJM explains that it also expanded the pool of eligible 
supply by permitting participation from resources capable of achieving commercial 
operation beyond the timeframe required for the 2028/2029 BRA.  PJM contends that 
under a pay-as-bid structure, such competition should exert downward pressure on 
procurement costs and improve the efficiency of the RBP procurement process.    
Finally, PJM argues that the implementation of market mitigation measures in a 
pay-as-bid construct can be difficult to verify and ineffective.127  PJM states that in a  
pay-as-bid approach, unlike a uniform clearing price construct where sellers are expected 
to offer a marginal cost, sellers are more likely to offer the expected clearing price.  PJM 
states that given offers will likely have less variation and information underlying them, it 
can be difficult and ineffective to determine offers exhorting market power. 
123 PJM states that the Commission, under somewhat similar circumstances, has 
previously found the pay-as-bid approach to be just and reasonable.  Transmittal at 69-70 
(citing Cal. Indep. Sys. Operator Corp., 153 FERC ¶ 61,001, at PP 2, 8, 15, 28 (2015)). 
124 Transmittal at 66-67, 70 (citing PJM, Intra-PJM Tariffs, OATT ATT DD.6.5, 
OATT ATTACHMENT DD.6.5 Mitigation (2.0.0), § 6.5(a)(ii)(C)). 
125 Id. at 68. 
126 Id. (citing Charles River Associates Survey Results at 5). 
127 Id. at 71.

Docket Nos. ER26-3380-000 and EL26-108-000 
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ii.
Responsive Pleadings 
Several parties criticize PJM’s RBP proposal for what it lacks.  The Market 
Monitor, for example, argues that the PJM RBP proposal would violate fundamental 
elements of the PJM capacity market design, which include the use of a single-price 
clearing mechanism, locational constraints, and market power mitigation rules.  The 
Market Monitor argues that PJM’s decision not to include locational requirements risks 
customers paying higher RPM prices in price-separated Locational Deliverability Areas, 
in addition to paying for additional transmission and higher energy prices as expensive 
local resources are required to serve data centers rather than the RBP Resources.128
Many other parties argue that the lack of locational constraints in the RBP is 
unjust and unreasonable.  PIOs and JCA argue that the Commission should modify        
the proposal to require that RBP Resources be sited in the same Electric Distributor 
zone/area as the load they serve, which would avoid costly transmission infrastructure 
buildout and delays.129  JCA similarly contends that the absence of locational criteria for 
RBP procurements poses unjustified cost risks for ratepayers.  AEP avers that the lack of 
a locational deliverability requirement could require customers to fund RBP Resources 
that are not deliverable to their zone, while resources that are necessary to address local 
reliability needs may not be procured at all.   
JCA contends that PJM’s assertion that it does not have information needed to 
determine locational parameters for 15-year term capacity commitments cannot be 
reconciled with PJM’s intention to allocate RBP costs to zones based on their large load 
forecasts.  PIOs also argue that PJM’s point that it lacks the necessary information to 
calculate locational parameters 15 years out is flawed because PJM does have some
locational information that it could use, similar to the three-year-forward forecast for the 
RPM.  PIOs insist that any locational considerations (even ones with a less certain 
projection than the three-year forecast of the RPM) will be better than none.  AEP 
similarly contends that PJM’s claim that it cannot predict future CETO or CETL values 
128 Market Monitor Protest at 7-8, 11. 
129 PIOs Protest at 16, 28, 34; JCA Protest at 36-37.  The Market Monitor similarly 
notes that PJM could require that the generation to serve a data center must be in the 
same Locational Deliverability Area as the data center.  Market Monitor Protest at 11.  
PIOs assert that the risks associated with high Network Upgrade costs are not speculative, 
highlighting RRI as an example, where 10 of the 51 projects withdrew from the 
interconnection process.  PIOs Protest at 19-20 (citing PJM, Cycle Service Request Status 
(July 2023), https://www.pjm.com/planning/m/cycle-service-request-status); AEP Protest 
at 17.

Docket Nos. ER26-3380-000 and EL26-108-000 
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with precision does not eliminate the need to establish a reasonable relationship between 
the resources procured and the reliability benefits for which customers are charged.130
Parties similarly express concerns that PJM’s proposal includes no direct market 
power screens or mitigation.  JCA argues that the RBP fosters the exercise of seller-side 
market power and is unlikely to secure the least-cost combination of resources.131  JCA 
states that PJM offers no supporting evidence that the resulting procurement price will be 
the result of true price competition, or that the outcome will reflect the marginal cost of 
the resources to be procured.  JCA states that every resource eligible to offer into the 
RBP can bid to raise prices to the $555/MW-day average price cap regardless of its 
marginal cost or that of its competitors, allowing the exercise of seller-side market power.  
JCA argues that PJM admits that market power concerns remain because it acknowledges 
bidders are most likely to offer the expected clearing price and not their own marginal 
cost of production.  In contrast to PJM’s statements that there is a sufficient number of 
potential suppliers to discipline market power concerns, JCA states that only about 80 of 
the 397 projects identified in the Charles River Associates Survey Results claim an 
ability to achieve commercial operation by the 2028/2029 delivery year and only 3% of 
all projects are under construction.
JCA and NOVEC question whether PJM has accommodated sufficient 
competition.  According to NOVEC, the companies with the wherewithal to prepare 
offers on an expedited basis and accept the uncertainty risk are likely to be staffed 
sufficiently to gamble on whatever the RBP rules might turn out to be without detracting 
from their established sources of revenue and have significant market share of PJM’s 
existing generation.132  NOVEC argues that if more time were afforded, more participants 
might think through ways to offer at lower rates and still be profitable.  JCA argues that 
not allowing commitment terms ending before 2042/2043 excludes resources that can 
energize in time for the 2028/2029 delivery year but are unwilling or unable to be bound 
through the 2042/2043 delivery year.  JCA asserts that PJM does not defend the 15-year 
commitment term as necessary to cure the reliability shortfall or compare the term against 
shorter alternatives, despite the Charles River Associates Survey Results indicating 
interest from resources in shorter terms.133
To expedite new capacity that can address the reliability shortfall, Amazon 
requests that the Commission direct PJM to provide an accelerated interconnection 
130 JCA Protest at 28-29; PIOs Protest at 23; AEP Protest at 17 n.56. 
131 JCA Protest at 17-22.  See also Market Monitor Protest at 13. 
132 NOVEC Protest at 5.  See also OCC Protest at 10. 
133 JCA Protest at 14 (citing Charles River Associates Survey Results at 5).

Docket Nos. ER26-3380-000 and EL26-108-000 
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process for RBP Resources and resources supported by executed bilateral capacity 
arrangements with new large loads.134  DCC encourages continued interconnection and 
permitting reforms.135
iii.
Determination 
We are unpersuaded by arguments that PJM’s filing is unjust and unreasonable 
because it lacks locational constraints and direct market power mitigation.  First, we find 
that the proposal’s lack of locational constraints does not render PJM’s overall proposal 
unjust and unreasonable.  Specifically, the volume of capacity that PJM will procure 
through the RBP auction—up to 6,831 MW—is relatively small compared with total 
existing supply in PJM (149 GW), so even if RBP Resources are not located in the exact 
same Locational Deliverability Areas as new loads, the effect of any locational 
constraints should be limited.  Moreover, as PJM explains, the RBP is designed to 
address the PJM Region’s capacity shortfall, such that it is addressing an effectively 
region-wide problem.136  PIOs are correct that, depending on where RBP Resources 
choose to site themselves, significant Network Upgrades could be triggered.  But one can 
reasonably assume that RBP Resources will include anticipated Network Upgrade costs 
in their RBP Sell Offers—meaning that RBP Resources that anticipate significant 
Network Upgrade costs will be less likely to clear in the RBP auction. 
Second, we find that the lack of direct market power screens or mitigation for the 
RBP does not render PJM’s overall proposal unjust and reasonable.  As PJM explains, in 
the context of a pay-as-bid structure with a maximum willingness to pay set at $555/MW-
day, the effectiveness of such measures would be limited.  In addition, PJM’s proposed 
average-price cap of $555/MW-day further disciplines costs by increasing the risk that 
high offers do not clear.  And as PJM argues, the exercise of market power is unlikely if 
even a portion of the more than 130 GW of supply identified in the Charles River 
Associates Survey Results decides to participate and drive down prices.137
134 Amazon Comments at 6. 
135 DCC Comments at 6-8. 
136 Transmittal at 33. 
137 Charles River Associates Survey Results at 5.

Docket Nos. ER26-3380-000 and EL26-108-000 
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3.
Topics for Discussion in Paper Hearing Procedures 
a.
PJM’s RBP Proposal May Be Unjust and Unreasonable 
Absent Modifications 
i.
Cost Allocation 
(a)
Cost Allocation at the Electric Distributor 
Zone/Area Level138
(1)
Filing 
PJM proposes to allocate the Initial RBP Target MW to each Electric Distributor 
zone/area using that zone/area’s pro rata share of the difference between the forecasted 
Load Adjustments139 for the 2026/2027 delivery year and the 2028/2029 delivery year.140
An Electric Distributor zone/area’s initial difference in Load Adjustments may then be 
reduced by Qualifying RBP Offset UCAP MW (referred to hereinafter as “offset 
capacity”), converted to load MW, and opt-outed load, as summarized further below.141
PJM also proposes to decrement the Initial RBP Target MW by both the amount of 
regionwide offset capacity and the UCAP obligation value of opted-out load to derive the 
Final RBP Target MW.142  PJM proposes then to allocate the costs of the RBP based on 
each Electric Distributor zone/area’s final assigned share of the Final RBP Target MW, 
which shall remain constant throughout the fixed 15-year term.   
PJM argues that the proposed Electric Distributor zone/area cost allocation method 
roughly assigns RBP Charges to the zone/areas with reported new load that is not 
138 The PJM Region is divided into about 20 Electric Distributor-administered 
Zones that are further divided into numerous “zone/areas” comprised of LSEs. 
139 As discussed further below, Load Adjustments are “any MW quantity of 
adjustments to summer peak load at the ‘zone/area’ level and summed by Zone as further 
detailed in PJM Manuals.”  PJM, Intra-PJM Tariffs, RAA, art. 1 (Definitions) (48.2.0). 
140 Proposed Tariff, attach. DD, § 18.3 (0.0.0), § 18.3(a). 
141 PJM proposes to divide submitted offset capacity MW by the 2028/2029 BRA 
Forecast Pool Requirement “to identify the amount of load that is being served by those 
offset MW.”  Transmittal, attach. C (Affidavit of Danielle Croop) ¶ 48 (Croop Aff.).  
142 Proposed Tariff, attach. DD, §18.1 (0.0.0), § 18.1(b).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 40 - 
matched with new capacity.143  According to PJM, these Electric Distributor zone/areas 
and underlying LSEs can be said to have caused the resource adequacy shortfall reflected 
in the 2028/2029 BRA.  PJM therefore contends that applying the method set forth in 
RAA, Schedule 8, with adjustments for offset capacity roughly assigns Electric 
Distributor zone/areas that caused the shortfall with a share of the RBP Charges. 
(2)
Responsive Pleadings 
Parties express numerous concerns with PJM’s proposed cost allocation method 
for RBP costs at the Electric Distributor zone/area level.  Several parties argue that PJM’s 
proposal to fix the cost allocation for 15 years conflicts with PJM’s proposal to base that 
cost allocation on only one snapshot of forecasted load growth.144  AEP contends that 
PJM’s proposal is unreasonable absent some allowance for adjustment to the allocation 
over time.145  Amazon states that PJM’s proposal to base cost responsibility on a single 
snapshot of forecasted load growth, rather than updating the allocation as load actually 
materializes, is inconsistent with cost causation and beneficiary pays principles.146
Amazon argues that the proposed method is problematic because a capacity allocation 
determined before load materializes will begin to diverge from actual cost causation.  
NOVEC asserts that PJM has not explained why this snapshot in time is appropriate 
beyond references to Schedule 8 of the RAA.147  Vistra argues that although PJM claims 
that the 15-year contract term will provide financing certainty, it is not clear why the cost 
allocation at the Electric Distributor zone/area level needs to be frozen to accomplish that 
goal.148  AEP believes that the RBP financial obligations should follow the LSE serving 
143 Transmittal at 103. 
144 ICC and JCA emphasize that by offering only contract terms that terminate in 
2042/2043, the RBP may compound the impact of forecasting errors.  ICC Comments at 
4; JCA Protest at 34.  JCA asserts that PJM’s only support for the 15-year payout period 
is that it is needed to comply with the NEDC/PJM Governors’ Principles.  See also Blue 
Ridge Comments at 3-4 (expressing concern that a one-time allocation of costs may 
become unjust and unreasonable over the 15-year period). 
145 AEP Protest at 28. 
146 Amazon Comments at 2, 4-5. 
147 NOVEC Protest at 11, 18. 
148 Vistra Protest at 6.

Docket Nos. ER26-3380-000 and EL26-108-000 
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the large load customer whose load growth gives rise to the RBP responsibility, not the 
Electric Distributor for the zone/area in which that customer happens to be located.149
JCA questions the initial accuracy of PJM’s forecasted load growth, noting that 
PJM’s large load forecasts have fallen by more than half since April, from 14.8 GW to 
6.8 GW.150  According to ICC, even if the regional load forecasts remain roughly 
accurate, failure to accurately forecast the locations where such growth will materialize 
may result in the wrong zones shouldering the costs.151  Policy Integrity contends that if 
this is the case, PJM’s proposed RBP cost allocation is unlikely to even be “roughly 
commensurate” with the participants who receive the benefit of that capacity.152  NOVEC 
argues that the problem with relying on Load Adjustments is that, even if they are “firm,” 
they are based on economic circumstances that no longer exist.  NOVEC believes that the 
RBP will raise the costs of data center loads, which will either prompt marginal data 
center projects to withdraw or cause data centers to relocate to areas not assessed RBP 
Charges.153
To address the perceived problems caused by a static RBP cost allocation, 
Amazon urges the Commission to require PJM to update the allocation of RBP costs 
periodically to reflect actual incremental load growth over the RBP commitment period.  
Amazon argues that this would reduce the risk of allocating stranded costs to existing 
customers and eliminate the perverse incentive for new large load customers to 
strategically site in zones initially assigned small obligations.154  ICC maintains that PJM 
149 AEP Protest at 31. 
150 JCA Protest at 12 (citing PJM, Reliability Backstop Procurement Design: 
Reliability Backstop CIFP11 (Apr. 2026), https://www.pjm.com/-
/media/DotCom/committees-groups/cifp-rbp/2026/20260416/20260416-item-05---pjm-
reliability-backstop-procurement-design---pjm-presentation.pdf; Croop Aff. ¶ 4).   
151 ICC Comments at 4.   
152 Policy Integrity Comments at 19.  See also JCA Protest at 5 (arguing that if 
forecasted load fails to materialize, “other customers in the affected zone will be assigned 
the RBP costs, barring a binding agreement for the large load to cover its stranded 
costs”). 
153 NOVEC Protest at 18-19. 
154 Amazon Comments at 4-5.

Docket Nos. ER26-3380-000 and EL26-108-000 
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should have proposed a mechanism to moderate any potential forecasting error, such as 
cost reconciliation.155
NOVEC argues that PJM’s proposed cost allocation method violates the cost 
causation principle by failing to recognize the structural causes of the capacity shortfall 
beyond load growth, such as generator retirements due to state policies.  NOVEC asserts 
that many generator retirements were precipitated by the policies of states whose Electric 
Distributors will not be bearing RBP Charges and the RBP Collateral requirement for 
LSEs.156  According to the Market Monitor, the inclusion of all loads in PJM’s initial 
procurement target (due to Load Adjustments including all types of load) is unduly 
discriminatory because non-data-center loads do not present the extraordinary 
circumstances—large volumes of MW being added quickly—that the RBP should 
address.157
NOVEC contends that PJM’s cost allocation method does not adequately account 
for the market-wide benefits that RBP Resources may provide by lowering prices in the 
RPM Auctions through their $0/MW-day offers.158  NOVEC argues that the RBP’s 
contract-for-difference settlement structure compounds this mismatch.  Noting that RBP 
Resources receive RPM revenues that offset their RBP commitment payments, NOVEC 
argues that if the mandatory $0/MW-day offers of RBP Resources contribute to a lower 
RPM clearing price, those resources would receive less RPM revenue and the 
corresponding RBP settlement obligation would increase.  NOVEC maintains that RBP 
buyers therefore may bear larger RBP Charges while capacity purchasers in the RPM 
benefit from the lower RPM price. 
Parties also fault PJM for not providing a fuller explanation of why and how it 
uses Load Adjustments as the foundation of its cost allocation method.159  EKPC argues 
that it is unclear whether PJM is properly using the information from Table B9b from the 
2026 PJM Load Forecast to ensure Electric Distributor zone/areas receive correct 
155 ICC Comments at 4. 
156 NOVEC Protest at 9-11 (citing PJM, Energy Transition in PJM: Resource 
Retirements, Replacements & Risks 6-7 (Feb. 2023), https://www.pjm.com/-
/media/DotCom/library/reports-notices/special-reports/2023/energy-transition-in-pjm-
resource-retirements-replacements-and-risks.ashx). 
157 Market Monitor Protest at 18. 
158 NOVEC Protest at 15-16. 
159 See, e.g., NOVEC Protest at 18 (arguing that PJM’s Load Adjustment process 
is “somewhat of a black box”).

Docket Nos. ER26-3380-000 and EL26-108-000 
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allocations, given that some Electric Distributor zone/areas cross state lines.160  Equinix 
asks the Commission to direct PJM to provide affected loads with sufficient transparency 
into the Load Adjustment data underlying RBP cost allocation, subject to appropriate 
confidentiality protections, together with a process to correct demonstrable errors or 
duplication.161
(3)
Answers 
In response to protests regarding PJM’s proposed cost allocation method for RBP 
costs at the Electric Distributor zone/area level, PJM argues that (1) the Commission has 
long held that relying on snapshots is an acceptable and appropriate method for 
establishing baselines or targets, (2) the capacity shortfall 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 (3) the target 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.  PJM argues that Load Adjustments need not identify specific non-
jurisdictional loads or be limited to one type of load (e.g., new data center customers) 
when the resource adequacy shortfall is caused by all types of loads that comprise the 
subject Load Adjustments.162
Parties filed answers in response to PJM’s answer.  NJBPU is concerned that 
substantial discrepancies exist in the inputs each Electric Distributor used to develop their 
Load Adjustments, and that these discrepancies will result in a discriminatory cost 
allocation outcome.163  NJBPU explains that its staff recently met with Electric 
Distributors to discuss 2027 Load Adjustments, pursuant to a new process established 
under recent revisions to PJM Manual 19.164  NJPBU maintains that it is now clear that 
the 2026 Load Adjustments used to determine PJM’s proposed RBP cost allocation 
method relied on data with substantially different characteristics across the PJM footprint.  
NJBPU explains that, in New Jersey, while some Electric Distributors reported load 
growth only for new large loads of 50 MW and above, other Electric Distributors 
160 EKPC Protest 20. 
161 Equinix Comments at 2. 
162 PJM Answer at 60-61, 64. 
163 NJBPU Answer at 3. 
164 Id. at 4 (citing PJM, Manual 19: Load Forecasting & Analysis, attach. B (June 
30, 2026), https://www.pjm.com/-/media/DotCom/documents/manuals/m19.pdf (adding 
the RERRA Review requirement)).

Docket Nos. ER26-3380-000 and EL26-108-000 
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reported all Load Adjustments with no MW threshold.  Furthermore, NJBPU states that 
presentations from PJM’s September 2025 Load Analysis Subcommittee suggest that 
these inconsistencies could be regional, with the result being that Electric Distributors 
receive different RBP cost allocations based not on load growth alone, but on their 
chosen characteristics for Load Adjustments.  For example, NJBPU notes that 
FirstEnergy’s presentation states it uses loads 50 MW or greater as inputs to the Large 
Load Adjustment, while Duke Energy states that it reported expansions of 20 MW or 
greater—and PJM later removed Duke Energy’s Load Adjustment because PJM 
determined its economic models would capture the load growth.165  According to NJBPU, 
it is unclear how pervasive these different treatments were because reporting Electric 
Distributors generally did not specify whether they used a MW threshold.  NJBPU 
contends allocating costs using these inputs is thus unduly discriminatory because some 
loads less than 50 MW in one zone/area will take on RBP obligations, while loads of the 
same size in a different zone/area will not, solely based on whether their Electric 
Distributors included the loads in their Load Adjustments.  NJBPU believes that PJM can 
resolve this issue after the RBP is held but before cost allocation by submitting a 
compliance filing to implement a consistent MW threshold for Load Adjustments.166
The Market Monitor argues that PJM’s proposed 6,831 MW procurement target, 
based on the capacity shortfall recorded for the 2028/2029 BRA, is no longer correct 
because of changes in data center loads.167  The Market Monitor states that the data center 
load forecast for the 2028/2029 BRA was based on Load Adjustments received by PJM 
before September 5, 2025.168  The Market Monitor asserts that, since then, 4,017 MW of 
165 Id. at 4-5 (citing FirstEnergy, PJM LAS Large Load Adjustment Presentation, 
at 4 (Sept. 2025), https://www.pjm.com/-/media/DotCom/committees-
groups/subcommittees/las/2025/20250916/20250916-item-04h---first-energy-large-load-
request.pdf; Duke Energy, Approach to Large Load Adjustments 3 (Sept. 2025), 
https://www.pjm.com/-/media/DotCom/committees-
groups/subcommittees/las/2025/20250916/20250916-item-04l--duke-large-load-
request.pdf; PJM, Load Adjustment Request Summary for 2026 Load Forecast – 
Preliminary 9 (Nov. 2025), https://www.pjm.com/-/media/DotCom/committees-
groups/subcommittees/las/2025/20251124/20251124-item-03---large-load-adjustment-
requests-summary.pdf). 
166 Id. at 5-6. 
167 Market Monitor Answer at 15. 
168 Id. at 14-15 (citing PJM, Large Load Adjustment Discussion (Oct. 2025), 
https://www.pjm.com/-/media/DotCom/committees-
groups/subcommittees/las/2025/20251028/20251028-item-05---large-load-

Docket Nos. ER26-3380-000 and EL26-108-000 
- 45 - 
data center load, or 42% of the forecasted increase in the data center load between the 
2026/2027 delivery year and 2028/2029 delivery year, have been cancelled or delayed as 
of September 21, 2026.169  The Market Monitor states that of this 4,017 MW, the 
Dominion Electric Distributor accounts for 51%, while the AEP-Ohio Electric Distributor 
accounts for 29%.  The Market Monitor contends that after accounting for these data 
center cancellations and delays, the capacity shortfall for the 2028/2029 BRA would be 
reduced from 6,831 MW to 3,055 MW.170
(b)
Cost Allocation at the LSE Level 
(1)
Filing 
PJM proposes that cost allocation to LSEs within an Electric Distributor zone/area 
be based on the state- and/or RERRA-determined allocation of cleared RBP UCAP MW, 
as reported by each Electric Distributor to PJM.171  PJM thus proposes a new defined 
term, the RBP Obligation or RBO, to refer to this state- and/or RERRA-determined 
allocation.  PJM argues that the RBO permits states and/or RERRAs to rely on their own, 
disparate definitions of data centers and large loads, and to determine which retail 
customers should be allocated RBP Charges.172  According to PJM, its authority over 
wholesale markets does not extend to dictating the allocation of costs to retail load and, 
for purposes of cost allocation to large loads, each state and/or RERRA may have its own 
adjustments.pdf).  
169 The Market Monitor states that its calculation of 4,017 MW is based on 
tracking of data center project status by Industrial Info Resources 
(https://www.industrialinfo.com) corroborated by publicly available data.  Id. at 15 n.29.  
The Market Monitor explains that it does not have access to project-level data behind 
Load Adjustments requested by Electric Distributors.  The Market Monitor further states 
that it considered only cancelled and delayed data center projects that were originally 
scheduled to be in service by 2029 as indicated by the Industrial Info Resources tracking 
data.  Regarding its claim that 4,017 MW represents 42% of PJM’s calculated increase in 
data center load, the Market Monitor states that PJM included 11,993 MW of data center 
load in the 2026/2027 BRA and 21,474 MW in the 2028/2029 BRA.  Id. at 15 n.28.  The 
Market Monitor states that the cancelled or delayed data center load of 4,017 MW as of 
September 21, 2026, represents 42% of the 9,481 MW increase (21,474 MW minus 
11,993 MW).   
170 Id. at 18. 
171 Proposed Tariff, attach. DD, § 18.3(b). 
172 Transmittal at 98.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 46 - 
method, developed in accordance with its unique needs and considerations.  If Electric 
Distributors with allocated RBP UCAP MW do not report RBOs by 60 days prior to the 
2028/2029 delivery year, PJM proposes to 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 already determined in RAA, Schedule 8.  That is, PJM 
would allocate the RBP costs assigned to an Electric Distributor zone/area among the 
LSEs in that zone/area in the same manner that it currently allocates RPM costs. 
In support of its proposed cost allocation method, PJM states that it relies on the 
best information available to track detailed information about the large loads and the 
various LSEs serving such large loads from every state and RERRA in the PJM Region.  
PJM argues that states and RERRAs are in a better position to identify large loads and 
allocate the cost of RBP Charges to the LSEs that serve them.173  PJM asserts that states 
and RERRAs have granular information about large loads within their borders.  PJM 
explains that it has tracked Load Adjustments in zone/areas to the level of granularity that 
is feasible.174  PJM notes that the proposed cost allocation method roughly assigns RBP 
Charges to the Electric Distributor zone/areas with reported new load that is not matched 
with new capacity.  PJM argues that these Electric Distributor zone/areas and LSEs can 
be said to have caused the resource adequacy shortfall reflected in the 2028/2029 BRA.  
Thus, PJM argues, a cost allocation method that provides PJM states and/or RERRAs the 
ability to determine the specific RBOs that should be assigned to LSEs within an Electric 
Distributor zone/area, as well as the ability to cost allocate to end-use customers in their 
respective states in accordance with their laws and policies, supports the NEDC/PJM 
Governors’ Principles, including the principle that the cost of new capacity should be 
allocated to data centers that have caused the need for additional capacity in the PJM 
Region. 
(2)
Responsive Pleadings 
Several parties contest PJM’s proposed cost allocation method for RBP costs at 
the LSE level, including its primary component that depends on RERRAs and states to 
report RBOs.  According to some parties, PJM’s proposal unreasonably relies on state 
laws that do not exist yet.175  NOVEC contends that PJM’s proposal provides insufficient 
173 Id. at 102-03, 107. 
174 Id. at 103 (citing S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 88 (D.C. Cir. 
2014) (“feasibility concerns play a role in approving rates, such that the Commission is 
not bound to reject any rate mechanism that tracks the cost-causation principle less than 
perfectly.”)). 
175 EKPC Protest at 37 (“PJM cannot make an otherwise insufficient federal rate 
design just and reasonable by requiring Electric Distributors, states, or RERRAs to

Docket Nos. ER26-3380-000 and EL26-108-000 
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time for states to pursue cost allocation methods by the 2028/2029 delivery year.1  JCA 
calls for a true-up mechanism or abeyance if states do not implement their cost allocation 
methods in time.176  Amazon argues that state regulators can allocate only the costs that 
PJM has first assigned to the relevant Electric Distributor zone/area, meaning protests 
applicable to that level of cost allocation also apply at the LSE level.177  OCC describes 
various risks of cost shifts to consumers if state cost allocation fails.178
RESA asserts that PJM’s proposal does not explain how RBP costs will be 
assigned to LSEs serving large load customers in retail-choice states as those customers 
may switch from one LSE to another during the 15-year term.179  AEP similarly argues 
that PJM’s proposal is lacking in details because it does not explain which party bears 
responsibility if LSEs decide not to pay their allocated share of RBP Charges, or if their 
load commitments shift over time, or if an LSE disputes their previously allocated share 
of RBP Charges.180
PA OCA argues that for states to determine the RBO values, they would have to 
determine and approve methods for RBO Peak Load Contributions, but that states lack 
jurisdiction to do so.  PA OCA states that the Commission should exercise its jurisdiction 
over the Transmission Owners’ RBO methodologies, which would be a “natural 
extension” of the Commission’s jurisdiction over the Peak Load Contribution and 
Network Service Peak Load methodologies in Tariff Attachment M-2s.181  PJMICC 
similarly argues that PJM must require utilities to set forth their RBP-related 
methodologies in their Tariff Attachment M-2s or some other filing subject to review by 
supply the missing cost-causation analysis”); EKPC September 18 Answer at 7-8; 
FirstEnergy Protest at 14 (citing N.Y. State Pub. Serv. Comm’n v. FERC, 104 F.4th 886 
(D.C. Cir. 2024); N.Y. Indep. Sys. Operator, Inc., 183 FERC ¶ 61,130 (2023); Kan. Corp. 
Comm’n v. FERC, 881 F.3d 924 (D.C. Cir. 2018)); Movants Protest at 16-17; OCC 
Protest at 7.  Ohio FEA and DCC, to the contrary, support allowing states to determine 
cost allocation to large loads.  DCC Comments at 6; Ohio FEA Comments at 4. 
176 JCA Protest at 35-36. 
177 Amazon Comments at 4. 
178 OCC Protest at 6-15. 
179 RESA Protest at 9. 
180 AEP Protest at 31. 
181 PA OCA Protest at 11, 14-16, 24.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 48 - 
state commissions.  Otherwise, PJMICC argues, “retail cost protections for existing 
customers will inevitably fail.”182
EKPC and SMECO argue that PJM’s proposal improperly expands the role of an 
Electric Distributor in PJM.  They contend that PJM’s proposal assigns Electric 
Distributors a series of functions that exceed the metering and data-reporting functions 
Electric Distributors have historically performed for PJM under section 11.3 of the PJM 
Operating Agreement (OA).  They assert that these functions include responsibilities 
related to not only LSE cost allocation, but also the proposed RBP rules pertaining to 
offset capacity, opt-outs, DER and Demand Resource participation, and collateral 
requirements.183  SMECO, for example, contends that PJM has called on Electric 
Distributors to develop and provide distribution-impact studies for RBP DER 
Aggregation Resources. 
EKPC argues that, pursuant to the OA definition of Electric Distributor, Electric 
Distributors may or may not engage in Commission-jurisdictional activities.  Thus, 
EKPC argues, there is no way to know whether they are “public utilities” over which the 
Commission may exercise plenary jurisdiction under Part II of the FPA.184  EKPC states 
that under FPA section 201(b), the Commission is explicitly precluded from exercising 
jurisdiction over “facilities used in local distribution or only for the transmission of 
electric energy in intrastate commerce.”185  More generally, EKPC argues that the RBP 
proposal is inconsistent with the boundaries of federal and state jurisdiction because it 
inappropriately places obligations on Electric Distributors and states or RERRAs.  EKPC 
asserts that determining cost allocations to LSEs and the associated collateral 
requirements is within the Commission’s primary regulatory authority.  EKPC further 
argues that because not all electric distribution companies are PJM Members, an attempt 
to delegate such a role to distribution-level utilities creates jurisdictional overreach by 
bringing such entities into a Commission-jurisdictional ratemaking role.  EKPC also 
questions how PJM’s proposal will be implemented in zones where not all of the load is 
served by Electric Distributors.186
182 PJMICC Comments at 6, 8 (also arguing that PJM “must revise its billing 
practices to tag/track RBP-related costs”). 
183 SMECO Comments at 2, 4-7; EKPC Protest at 12, 35-41 (citing EKPC Protest, 
attach. 1 (Affidavit of Adam Bednarczyk)). 
184 EKPC Protest at 40 (citing 16 U.S.C. § 824(e)). 
185 Id. (citing 16 U.S.C. § 824(b)(1)). 
186 Id. at 41-45.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 49 - 
Vistra argues that PJM’s default proposal to allocate RBP costs to all LSEs, 
regardless of whether they contributed to the current resource adequacy shortfall, is also 
unjust, unreasonable, and unduly discriminatory.  Vistra asserts that the resource 
adequacy shortfall is the result of certain LSEs committing to serve more demand than 
they have supply.  According to Vistra, allocating the cost of covering the cumulative 
shortfall to LSEs that had no shortfall, and thus did not contribute to it, would be patently 
inconsistent with cost causation.  Vistra further argues that such entities will not 
meaningfully benefit from RBP because they already procured the capacity they need.  
Vistra contends that to the extent those entities enjoy any benefits from the RBP, they are 
trivial in relation to the costs that RBP promises to impose.187
ODEC similarly argues that using LSEs as the default payer, with no assurance of 
the level of costs or that those costs will be allocated to large loads, does not adhere to 
principles of cost causation.188  PPL asserts that PJM’s backup cost allocation to LSEs 
could result in LSEs that do not serve large loads receiving these obligations, thereby 
having nowhere to assign them except to other customers, which would be inconsistent 
with the Ratepayer Protection Pledge.189
EKPC argues that LSEs will be harmed due to the uncertainty of whether they will 
face the RBO cost allocation in which only some LSEs are charged or the default cost 
allocation in which all LSEs are charged.  EKPC asserts that PJM thus has failed to 
provide “clear and transparent procedures” to allow an LSE to determine the amount of 
costs it may be allocated under the RBP.190  EKPC also notes that under the proposal, 
costs to LSEs are not fixed over the 15-year payment period, leading to further 
uncertainty.  
Several parties advocate for PJM to share RBP cost allocation data with states.191
AEU asserts that PJM should commit to monitoring and supporting state-level rate design 
187 Vistra Protest at 2-4; see also Blue Ridge Comments at 3-4; EKPC Protest at 
37-38; Movants Protest at 16-17; NCEMC Comments at 20-21; RESA Protest at 5. 
188 ODEC Comments at 4. 
189 PPL Protest at 13. 
190 EKPC Protest at 17-18 (citing Tri-State Generation & Transmission Ass’n, 175 
FERC ¶ 61,229 (2021)). 
191 See, e.g., DCC Comments at 6; Equinix Comments at 9-11; Google Comments 
at 8.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 50 - 
mechanisms and report progress to the Commission and to stakeholders.192  Without both 
information sharing and regulatory accountability, PJMICC argues that PJM’s proposal 
“leaves ultimate retail cost allocation rudderless” because states cannot determine retail 
prices “in a vacuum.”193  ICC states that it is unclear how states, particularly retail access 
states like Illinois, would be able to assign wholesale capacity costs to retail load in the 
manner PJM proposes and that developing such mechanisms will take time.  ICC requests 
that PJM clarify how states will determine RBOs and whether and how PJM plans to 
assist states in that process.194
(3)
PJM Answer 
In response to protests concerning the role of Electric Distributors in the RBP, 
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.  PJM argues 
that the RBP proposal calls for Electric Distributors to report information and act as a go-
between—roles that are harmonious with the existing role that Electric Distributors have 
played in PJM.  PJM states that the RBP proposal requires that Electric Distributors only:  
(1) communicate opt-out requests and provide supporting materials to PJM; (2) report 
capacity offsets and provide supporting evidence to PJM; (3) report state- or RERRA-
determined allocation; (4) report information that feeds the Electric Distributor zone/area 
allocation of the RBP procurement target and LSE daily formula; and (5) provide inputs 
that impact LSE collateral.  Ultimately, PJM states, it is PJM and, where applicable, 
states and RERRAs—not the Electric Distributors supplying the underlying inputs—that 
will determine how such inputs inform cost allocation and credit requirements.195
PJM also argues that SMECO’s claim that PJM has called on Electric Distributors 
to develop and provide distribution-impact studies for RBP DER Aggregation Resources 
misconstrues the proposed Tariff language, which states that RBP Sell Offers from RBP 
Demand Resources and RBP DER Capacity Aggregation Resources must be 
accompanied by applicable Electric Distributor requirements.196  PJM states that it is not 
imposing requirements on Electric Distributors to develop new or additional studies or 
192 AEU Comments at 27-28. 
193 PJMICC Comments at 2-3, 7-9. 
194 ICC Comments at 5. 
195 PJM Answer at 10-11. 
196 Id. at 11 (citing Proposed Tariff, attach. DD, § 18.5 (0.0.0), §§ 18.5(f)(i)(12), 
18.5(f)(i)(13)).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 51 - 
requirements.197  PJM also clarifies that Electric Distributors perform a reporting or 
administrative role in the RBP and 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. 
Responding to protests regarding the default cost allocation approach, PJM argues 
that the backup method of allocation is an established, clear, and transparent method.  
PJM states that it lacks the necessary data to assign cost responsibility to the LSEs 
serving the retail load that gave rise to the Load Adjustment in every instance and thus, in 
the absence of state coordination, it is reasonable to use such a backup method.198
(c)
Related Provisions: Offset Capacity, Opt-
Outs, and FRR Entities Exclusion 
(1)
Filing 
To prevent double procurement, PJM proposes to decrease the Initial RBP Target 
by the amount of offset capacity.199  PJM proposes to credit offset capacity (converted to 
load MW) against an Electric Distributor zone/area’s change in forecasted load between 
2026/2027 and 2028/2029 and then recalculate all the procurement targets under that 
Electric Distributor given that forecast change.  Any entity can report offset capacity to 
PJM during the bid submission window, but Electric Distributors are required to provide 
reports and evidence of offset capacity in each of their respective zone/areas.  PJM 
determines the amount by which offset capacity may reduce the Initial RBP Target based 
on the applicable Effective Load Carrying Capability (ELCC) Class Ratings for the 
2028/2029 BRA or, where the relevant resources do not have ELCC Class Ratings, the 
estimated unit-specific UCAP values for such resources.  The capacity must not have 
previously cleared in RPM nor been previously committed in an FRR plan, as of the 
beginning of the RBP.  Offset capacity may be:  (1) a new build generation resource, 
including new resources that obtain Capacity Interconnection Rights (CIR) transferred 
from either deactivated resources or resources that have announced deactivation as of 
April 10, 2026;200 (2) incremental capacity created by an uprate of existing Generation 
197 Id. at 11-12. 
198 Id. at 69. 
199 Transmittal at 37; Proposed Tariff, attach. DD, § 18.2. 
200 PJM argues that because April 10, 2026 is the day that PJM first posted this 
eligibility requirement, such a cutoff date guards against resource owners potentially 
gaming retirements by, for example, entering a deactivation notice after this date only to 
claim that it is being repowered in advance of the RBP.  Transmittal at 41 n.111.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 52 - 
Capacity Resources, but only to the extent such incremental capacity is created through 
an increase in such Generation Capacity Resource’s ICAP and increase in CIRs 
associated with that Generation Capacity Resource; (3) incremental capacity created by 
the use of Surplus Interconnection Service; (4) repowering of a deactivated generation 
resource that deactivated prior to April 10, 2026; (5) incremental capacity, whether due to 
greater unforced capacity or a higher level of CIRs, created by an existing Generation 
Capacity Resource’s changing fuel type to a more efficient fuel type; or (6) Planned 
Demand Resource or Planned Distributed Energy Resources (DER) Capacity 
Aggregation Resources.  Under these rules, Energy Storage Resources are eligible. 
Offset capacity may be supported by signed bilateral contracts for at least five 
delivery years or by self-supply generation that is in an integrated resource plan with 
either associated generation in the PJM interconnection queue or signed bilateral 
contracts for at least five delivery years.201  To serve as offset capacity, both signed 
bilateral contracts and self-supply must be supported by documentation of an expected in-
service date of no later than June 1, 2032.202  The evidence must also demonstrate that the 
new capacity is matched with new load.  PJM argues that the five-year requirement 
ensures capacity is not transitory while not being so lengthy as to undermine the 
flexibility needed for commercial contracting.203
New load can provide offset capacity by participating as a Demand Resource or 
DER Capacity Aggregation Resource.204  Such load must offer their full load MW 
quantity into the RPM Auctions starting in the 2028/2029 Second Incremental Auction 
and continuing through the 2032/2033 delivery year.  Such new load can subsequently 
replace UCAP MW provided through such participation by purchasing offset capacity 
that comes from eligible generation or storage resources. 
The Initial RBP Target is also decremented where an Electric Distributor elects to 
opt out a zone/area in one of two circumstances.205  First, an opt-out may be requested 
where the Electric Distributor’s zone/area has rates that are not regulated by the states 
(e.g., cooperatives or municipal utilities) and is unable to address cost allocation 
associated with capacity procured in the backstop.  PJM states that during the stakeholder 
process, cooperatives raised the concern that Electric Distributors in a retail choice state 
201 Proposed Tariff, attach. DD, § 18.2(a). 
202 Proposed Tariff, attach. DD, § 18.2(b). 
203 Transmittal at 39. 
204 Proposed Tariff, attach. DD, § 18.2(c)(iii). 
205 Proposed Tariff, attach. DD, § 18.1(d).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 53 - 
not regulated by the state and not otherwise serving as the LSE for generation to the load 
would be forced to have its customers absorb the costs of an “overbuy” if a forecasted 
large load failed to materialize.  PJM states that unlike a state-regulated, investor-owned 
utility, cooperatives and municipal utilities are not governed by a state regulatory 
authority that would be responsible for addressing the potential reallocation of RBP costs 
to either other large loads or other zones within the state.206  The opt-out request must 
specify the associated MW quantity of load in the zone/area that will be opted out of the 
Initial RBP Target and be accompanied by supporting documentation demonstrating an 
inability to address cost allocation associated with capacity procured in the backstop, 
along with written support for such opt-out from the relevant state governor, RERRA, 
and interconnection customer(s).  Second, an Electric Distributor may also request to opt 
out of the RBP for up to the associated MW quantity of load that participates in a peak 
shaving adjustment program codified in state law, where an Electric Distributor’s 
zone/area addresses its capacity needs through such a program.207
Finally, PJM explains that FRR Entities are excluded from the Initial and Final 
RBP Targets as well as the RBP overall.208  PJM argues that the FRR, by design, is an 
opt-out of RPM, and the RBP is curing a resource adequacy gap from which FRR load 
and FRR capacity are already removed.   
(2)
Responsive Pleadings 
(i)
Offset Capacity 
Parties contest various aspects of PJM’s proposal to decrease the Initial RBP 
Target by the amount of offset capacity.  JCA and OPSI argue that to be consistent with 
PJM’s proposal to account for offset capacity, the Commission should require PJM to 
reduce the Initial RBP Target also to reflect demand reductions.  OPSI states that it views 
this modification to PJM’s proposal as “critical to protecting other customers.”209  In 
response, PJM argues that even if there have been some withdrawals of prospective large 
loads, that forecast nevertheless continues to predict steep load growth.  Thus, PJM 
206 Transmittal at 45. 
207 PJM cites one such law.  Id. at 45 n.121 (citing N.J. P.L.2026, C.32 (July 7, 
2026) (to be codified at N.J. Rev. Stat. Title 48); NJ A796, Bill Track 50 (last updated 
July 7, 2026), https://www.billtrack50.com/billdetail/1954539). 
208 Id. at 31 n.92; Proposed Tariff, attach. DD, § 18.1(c). 
209 JCA Protest at 5, 12, 34; OPSI Comments at 3-4 (arguing that if “new load,” as 
defined by PJM, terminates an electric service agreement or transmission service 
agreement, PJM should remove that load from its procurement target during the RBP).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 54 - 
argues, it does not need to decrease the RBP procurement target to account for large load 
withdrawals.210
PSCWV argues that the proposed offset qualifications are so complex and 
discouraging that PJM will likely understate the amount of offset capacity, resulting in an 
excessive Final RBP Target.211  EKPC contends that PJM’s proposal unfairly socializes 
the benefit of prudent resource planning by LSEs by allowing Electric Distributors to 
report offset capacity at only the Electric Distributor zone/area level.212  Equinix argues 
that it will be unfair if new loads providing offset capacity nevertheless face RBP 
Charges because their states or RERRAs fail to credit loads providing offset capacity.213
DCC requests that the Commission ensure PJM provides customers with sufficient 
information to understand what documentation will be required for offset capacity and 
how confidential commercial information will be protected.214
Amazon, FirstEnergy, and Talen argue that PJM should account for contracts 
between loads and existing generators if those contracts were executed prior to a certain 
date.  Otherwise, they argue, PJM’s proposal will disrupt existing commercial agreements 
and lead to double payments.215  In response, PJM argues that the purpose of the RBP is 
to procure new capacity to match new loads.  PJM argues that this approach helps ensure 
that capacity offsets and RBP procurements result in a genuine increase in regional 
capacity rather than simply shifting existing commitments among procurement 
mechanisms.  PJM argues that the fact that new load has contracted with an existing 
generation resource means that the existing generation resource is no longer serving 
existing load and the shortfall remains.  PJM argues that allowing such existing 
generation to offset this target would not contribute to closing the shortfall.  PJM also 
asserts that LSEs and large loads should have been on notice that change was coming, 
210 PJM Answer at 25. 
211 PSCWV Comments at 2-3. 
212 EKPC Protest at 15, 28-31; EKPC September 18 Answer at 16-17.   
213 Equinix Comments at 9.  See also NCEMC Comments at 3 (arguing that PJM’s 
proposal lacks clarity for LSEs on whether their own costs will be decreased in line with 
decrements to procurement targets resulting from offset capacity and opt-outs). 
214 DCC Comments at 3-4. 
215 Amazon Comments at 2 (advocating that PJM grandfather in existing contracts 
as of PJM’s filing date); First Energy Protest at 13; Talen Comments at 1 (asking PJM to 
recognize contracts executed prior to the release of the NEDC/PJM Governors’ Principles 
in January 2026).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 55 - 
and as sophisticated parties, they would have priced and valued in their contractual 
negotiations the risk of how PJM and the Commission would address the impacts of large 
loads causing the resource adequacy shortfall.216
Dominion and NOVEC note that PJM proposes to credit offset capacity 
(converted to load MW) against an Electric Distributor zone/area’s change in forecasted 
load between 2026/2027 and 2028/2029 instead of against the Electric Distributor 
zone/area’s Initial RBP Target.  They argue that this approach leads to double payments 
because some supply to serve incremental load was procured in the RPM Auctions.  They 
also note that PJM’s approach effectively socializes offset capacity among all an Electric 
Distributor’s zone/areas rather than targeting only the zone/area providing the offset 
capacity.  As an example, NOVEC explains that although its share of the Initial RBP 
Target is 1,303 MW, PJM’s proposal would require NOVEC to procure about 1,619 MW 
to fully offset its share.  NOVEC argues that is unjust and unreasonable to force RBP 
buyers to procure an excess of the target MW amount.  NOVEC contends that the RBP 
reduces other buyers’ obligations when a single buyer procures offset capacity, which 
creates a perverse incentive for buyers willing to risk assignment of the RBP Charges to 
do nothing with the hope that other RBP buyers enter bilateral arrangements and reduce 
the Final RBP Target.217
In response, PJM asserts that it is the Load Adjustments that drive the need for the 
RBP and therefore drive cost allocations to each Electric Distributor zone/area.  PJM 
contends that the fact that the actions of some LSEs or loads may reduce the RBP 
obligations of others is not inherently unjust and unreasonable and, instead, the benefit of 
pooled resources is a key feature of being in a Regional Transmission Organization.218
The Market Monitor argues that the proposed offset capacity rules allow inferior 
five-year capacity to displace 15-year capacity.  The Market Monitor asserts that PJM’s 
proposal creates strong incentives to provide inferior and shorter-term capacity to meet 
the 15-year demand.  In general, the Market Monitor asserts that PJM does not explain 
why offset capacity is held to a weaker standard than RBP Resources given that both are 
216 PJM Answer at 23-24, 65-67. 
217 Dominion Protest at 3, 6-7; NOVEC Protest at 17-18. 
218 PJM Answer at 70, 73.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 56 - 
being used to satisfy the reliability shortfall.219  The Market Monitor argues that all 
capacity that addresses the shortfall should be required to meet the same conditions.220
Equinix, on the other hand, supports the five-year minimum term for the bilateral 
contracts and bilateral procurement arrangements that may produce offset capacity 
because it strikes the right balance between supporting resource adequacy needs and 
maintaining commercially reasonable structures.221
Voltus notes that the proposed criteria for offset capacity will count “reactivated” 
generation and storage resources against an Electric Distributor’s RBP procurement 
target but not reactivated Demand Resource and DER sites, which may unduly 
discriminate against demand-side resources.222  Voltus argues that this difference in 
treatment ignores existing arrangements with Demand Resource sites willing to reactivate 
to contract with large loads.  In response, PJM states that it is amenable 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 RAA, Schedule 6 and 
Schedule 6.2, where such incremental capacity are not reliant 
on locations which previously provided capacity unless such 
previous locations represents additional capacity resulting 
from an investment in new generation or new storage 
resources at that location.223
Voltus responds that this Tariff language still fails to include reactivated Demand 
Resource and DER sites, which will disincentivize large volumes of potential new 
capacity with near-term availability in the 2027/2028 and 2028/2029 delivery years.224
Calibrant requests clarification that behind-the-meter generation projects can 
provide evidence that they are eligible as offset capacity under proposed Tariff, 
Attachment DD, section 18.2(c)(i), which Calibrant states is consistent with PJM’s 
219 Market Monitor Protest at 19-20. 
220 Id. at 21. 
221 Equinix Comments at 13. 
222 Voltus Protest at 3-9. 
223 PJM Answer at 29. 
224 Voltus Answer at 2-6.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 57 - 
position during the stakeholder process.225  In response, PJM reiterates that the eligibility 
requirements for offset capacity and RBP Resources are not the same.  PJM states that to 
the extent that generation provides capacity meeting the qualifications set forth in either 
proposed Tariff, Attachment DD, section 18.2(c), to provide offset capacity, or 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.226
AEU requests clarification of the offset capacity eligibility rules.  AEU states that 
proposed Tariff, Attachment DD, section 18.2(c) offers eligibility through three 
evidentiary pathways, but it is unclear whether behind-the-meter generation or storage 
backing a demand response arrangement may rely on the signed bilateral contract 
pathway in section 18.2(c)(i), available on equal terms to front-of-the-meter resources, or 
whether it is instead confined to the demand response pathway in section 18.2(c)(iii), 
which imposes two requirements not applicable under (c)(i):  that the resource offset the 
new load’s full MW quantity rather than a partial share, and that it be in place by the 
2028/2029 Second Incremental Auction or the load purchase replacement offset capacity.  
AEU requests that PJM clarify that behind-the-meter generation and storage backing a 
demand response arrangement is not categorically confined to the more restrictive 
pathway in section 18.2(c)(iii) solely because of its behind-the-meter configuration.227
AEU argues that the offset capacity provision also raises a threshold eligibility 
question.  According to AEU, proposed Tariff, Attachment DD, section 18.2(a), appears 
to limit offset capacity eligibility for demand-side resources to Planned Demand 
Response or Planned DER Capacity Aggregation Resource as described in RAA 
Schedule 6 and Schedule 6.2, potentially excluding reactivations of previously active 
sites and new capacity at existing sites, categories that generation and storage resources 
are expressly permitted to rely on under section 18.2(b).  AEU requests that PJM amend 
section 18.2(a) to align demand-side offset eligibility with the treatment already afforded 
to generation and storage under section 18.2(b), consistent with the stakeholder 
consensus reached on this issue.228
225 Calibrant Comments at 1-2. 
226 PJM Answer at 29. 
227 AEU Comments at 17. 
228 Id. at 17-18.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 58 - 
Constellation requests that the Commission direct PJM to modify the criteria for 
resources eligible to supply offset capacity to include energy resources that obtain new 
CIRs through an interconnection request.229
Equinix requests that the Commission direct PJM to publish requirements for 
demonstrating offset capacity, including the evidence PJM will accept and the process by 
which large loads may submit that evidence directly, before the RBP bid submission 
window opens.230
Tract argues that PJM should clarify the scope of agreements load can provide as 
evidence of qualifying as “new load” for the purposes of offset capacity.  Tract requests 
that PJM clarify that the undefined terms “electric service agreement” and “transmission 
service agreement” encompass executed agreements with LSEs or Transmission Owners 
that evidence a binding commitment by new load to achieve commercial operation by or 
during the relevant delivery year.  In response to Tract, 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.231  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.232
(ii)
Opt-Outs and FRR Exclusion 
Regarding PJM’s proposed RBP opt-outs, parties take various stances.  
FirstEnergy argues that the opt-out targeted at cooperatives and municipal utilities is 
unduly discriminatory because large load in those territories is no less real than large load 
in any other territory, and PJM provides no reasonable basis for treating such loads 
differently.233  In response, PJM reiterates that the opt-out was designed to address a 
limited regulatory gap faced by cooperatives and municipal utilities whose rates are not 
regulated by the states.  PJM argues that to the extent that cooperatives and municipal 
utilities’ rates are not governed by a state regulatory authority that would be responsible 
229 Constellation September 8 Answer at 3; Constellation September 21 Answer 
at 2-4. 
230 Equinix Comments at 2, 6. 
231 Tract Protest at 4. 
232 PJM Answer at 28. 
233 FirstEnergy Protest at 19-20.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 59 - 
for addressing the potential reallocation of RBP Costs to either large loads or other 
Electric Distributor zone/areas within the state, there is risk that those cooperatives and 
municipal utilities’ customers would absorb the costs of an “overbuy” if a particular large 
load fails to materialize.  Thus, PJM argues, the proposed opt-out should appropriately be 
limited only to those Electric Distributors that are not regulated by the state.234
ODEC notes that its members are rate-regulated and thus not eligible for the opt-
out.  ODEC thus argues for an unrestricted opt-out, asking the Commission to evaluate 
the opt-out consistent with its broader purpose of protecting smaller utilities from undue 
procurement risk while preserving flexibility for those entities best positioned to manage 
that risk.235  In response, PJM states that to the extent that ODEC is the LSE for its 
member cooperatives and ODEC is not subject to rate regulation by state commissions, 
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.236  NOVEC counters that a result of PJM’s 
proposal is that one Virginia cooperative, ODEC, can opt out while another Virginia 
cooperative, NOVEC, cannot.237  NOVEC argues that its RBP exposure is not reduced by 
being regulated by the state because its customers may still have to absorb the cost of an 
overbuy. 
JCA advocates for an opt-out for any LSE in an Electric Distributor zone/area that 
is allocated RBP Charges that has no large load customers.238  OELC calls for an opt-out 
for non-data-center large loads that are under 150 MW to protect existing 
manufacturers.239
Equinix supports the proposed opt-out for load participating in a state-codified 
peak shaving adjustment program because such load has already addressed its capacity 
needs.240  Base Power also seeks clarification that to qualify for the peak shaving opt-out, 
the deadline for any peak shaving adjustment plan submitted pursuant to the requirement 
234 PJM Answer at 30-31. 
235 ODEC Comments at 2, 6-9. 
236 PJM Answer at 31. 
237 NOVEC Answer at 8. 
238 JCA Protest at 35. 
239 OELC Comments at 1. 
240 Equinix Comments at 12.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 60 - 
of Tariff, Attachment DD-2 will be September 2027.241  In response, PJM confirms that 
peak shaving adjustment plans for the 2028/2029 Third Incremental Auction can be 
submitted as late as September 2027.242
Base Power seeks clarification from PJM that the peak shaving opt-out is not 
discounted and will be one-to-one.243  NJBPU also states PJM should clarify that planned 
peak shaving adjustments can qualify for the opt-out, one-for-one, if they are being 
pursued under a requirement codified in state law even if the program’s details are not yet 
finalized.244  In response, PJM 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 one-to-one ratio.245
Regarding PJM’s proposal to exclude FRR Entities from the RBP, EKPC and 
Vistra assert that the proposal is unduly discriminatory because PJM proposes to include 
LSEs that meet their reliability requirements through self-supply, even though such LSEs 
are similarly situated to FRR Entities.246  In response, PJM argues that the scope of RBP 
is to procure capacity for new large loads that did not bring their own capacity, which 
does not implicate FRR Entities who by definition must bring new capacity for all new 
loads within their territory or otherwise be subject to FRR Commitment Insufficiency 
Charges.247  EKPC answers that it does not argue that FRR Entities should be subjected 
to the RBP, but rather that PJM fails to explain why similar planning conduct by FRR 
Entities and self-supply LSEs warrants different treatment under the RBP.248
241 Base Power Comments at 2, 7-8. 
242 PJM Answer at 25-26. 
243 Base Power Comments at 2, 6-7. 
244 NJBPU Comments at 7. 
245 PJM Answer at 26. 
246 EKPC Protest at 45-47; Vistra Protest at 4-5. 
247 PJM Answer at 55-56 (citing PJM, Intra-PJM Tariffs, RAA, art. 1 and Schedule 
8.1D § 7). 
248 EKPC September 18 Answer at 11.

Docket Nos. ER26-3380-000 and EL26-108-000 
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(d)
PJM’s Proposal May Be Unjust and 
Unreasonable 
For purposes of determining whether a proposed cost allocation method is just and 
reasonable, both “[the Commission] and federal courts have long understood the [FPA’s] 
just-and-reasonable requirement ‘to incorporate a cost-causation principle.’”249  Under 
the cost causation principle, all Commission-jurisdictional rates and charges must “reflect 
to some degree the costs actually caused by the customer who must pay for them,”250 and 
costs must be allocated in a manner that is at least roughly commensurate with 
benefits.251  Compliance with this principle is evaluated by “comparing the costs assessed 
against a party to the burdens imposed or benefits drawn by that party.”252  Courts and the 
Commission have acknowledged that adherence to the cost causation principle does not 
require that cost allocation methods balance costs and benefits with “exacting 
precision.”253  Instead, the Commission may approve a given cost allocation framework if 
it “has an articulable and plausible reason to believe that the benefits are at least roughly 
commensurate with” the assigned costs.254  Consistent with this longstanding precedent, 
we apply the cost causation principle to evaluate PJM’s proposed method for allocating 
RBP costs.  
As an initial matter, we find PJM’s proposal to exclude FRR Entities from the 
RBP to be just and reasonable, and thus we do not include it in the list of topics that will 
be the subject of the paper hearing procedures established in this order.  We agree with 
PJM that the FRR Alternative, by design, is an opt-out of RPM and that the RBP 
addresses a resource adequacy gap from which FRR load and FRR capacity are already 
249 Tri-State Generation & Transmission Ass’n v. FERC, 170 F.4th 1254, 1261-62 
(10th Cir. 2026) (quoting Consol. Edison Co. of N.Y. v. FERC, 45 F.4th 265, 271 (D.C. 
Cir. 2022)). 
250 KN Energy Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992); see also Ky. 
Pub. Serv. Comm’n v. Am. Elec. Power Serv. Corp., 193 FERC ¶ 61,110 (2025) (Ky. 
Comm’n). 
251 See, e.g., Ill. Com. Comm’n v. FERC, 576 F.3d 470, 477 (7th Cir. 2009). 
252 Id. (citing Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1368 
(2004)).  
253 Coal. of MISO Transmission Customers, 172 FERC ¶ 61,099 at P 83 (quoting 
Midwest ISO Transmission Owners, 373 F.3d at 1369); see also Ill. Com. Comm’n, 576 
F.3d at 477. 
254 Ill. Com. Comm’n, 576 F.3d at 477.

Docket Nos. ER26-3380-000 and EL26-108-000 
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removed.255  FRR Entities are required to demonstrate in their FRR Capacity Plan that 
they have sufficient resources to meet their load obligations.  Accordingly, we find that 
FRR Entities have not contributed towards the resource adequacy gap that the RBP will 
address and, therefore, it is just and reasonable and consistent with the cost causation 
principle to exclude FRR Entities from being allocated costs associated with the RBP.  
We disagree with protesters who argue that PJM’s proposal is unduly discriminatory 
against LSEs that meet their reliability requirements through self-supply.256  Specifically, 
we find that such LSEs are not similarly situated to FRR Entities because, while both 
FRR Entities and LSEs that self-supply own or have contracted for the capacity needed to 
meet their load obligations, FRR Entities’ load and capacity are removed from RPM, 
while the load and self-supplied capacity of such LSEs are not.  Moreover, only FRR 
Entities entirely take on the risks of over- or under-supply in their own regions; LSEs that 
self-supply, on the other hand, continue to participate in RPM such that they can procure 
additional capacity or sell excess capacity in the RPM Auctions. 
We find that PJM’s proposed opt-out for qualifying cooperatives and municipal 
utilities may be unjust, unreasonable, and unduly discriminatory.  PJM states that 
qualifying cooperatives and municipal utilities should be permitted to opt out of the RBP 
because they lack state regulatory oversight, and therefore may be unable to assign costs 
to specific large loads.  Because cooperatives and municipal utilities serve large loads 
that are similarly situated to large loads served by other LSEs, allowing an opt‑out may 
be unduly discriminatory. 
With respect to cost allocation, as a general matter, we find that PJM’s proposed 
RBP cost allocation method may be unjust and unreasonable.  As discussed below, we 
make this finding because, based on the current record, PJM has not adequately 
demonstrated that its proposal is just and reasonable and consistent with the cost 
causation principle.  
255 Transmittal at 31 n.92. 
256 See TranSource, LLC v. PJM Interconnection, L.L.C., 168 FERC ¶ 61,119, at 
P 240 (2019) (“undue discrimination can only occur when two similarly situated 
customers are treated differently, and there is no justification for the differing 
treatment. . . .  In other words, a finding of undue discrimination requires a showing that 
(1) two classes of customers are treated differently; and (2) the two classes of customers 
are similarly situated.”.); Solar Energy Indus. Ass’n v. Midcontinent Indep. Sys. 
Operator, Inc., 185 FERC ¶ 61,186, at P 18 (2023) (to “prevail on an undue 
discrimination claim,” the party must show that it is similarly situated to others and that 
any different treatment between the similarly situated entities is not justified).

Docket Nos. ER26-3380-000 and EL26-108-000 
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Under the proposed tariff revisions, PJM “shall allocate the Initial RBP Target 
MW to each Electric Distributor’s zone/area using that zone/area’s pro-rata share of the 
difference between the forecasted Load Adjustments for the 2026/2027 Delivery Year 
and the 2028/2029 Delivery Year.”257  As a general matter, allocating RBP costs to 
Electric Distributor zone/areas based on a “snapshot” of load growth between 2026/2027 
and 2028/2029, adjusted down by qualifying offset capacity, may be just and reasonable, 
because it reasonably assigns costs to those responsible for the near-term capacity 
shortfall.  Thus, such zone/areas benefit from procurement of new resources to fill this 
urgent gap.  We generally find that PJM’s proposal to initially assign RBP costs to 
Electric Distributor zone/areas, with the ultimate cost allocation to the LSEs as 
determined by the state and/or RERRA and as reported to the Electric Distributor by 
PJM, may be just and reasonable, as it reflects the authority of PJM under the Tariff and 
respects the authority of the states and/or RERRAs.  However, we agree with concerns in 
the record that relying on Load Adjustments to measure load growth may be inconsistent 
or not reasonably capture forecasted load growth or actual large load growth; thus, PJM’s 
method for allocating RBP costs may be unjust and unreasonable.   
Specifically, based on PJM’s explanation in a previous proceeding of the way in 
which it avoids double counting when accounting for Load Adjustments,258 and 
comments in this record,259 it appears some large loads may never have been accounted 
for as Load Adjustments because PJM accounted for them when calculating the initial 
load forecast.  In short, the delta accounts for net load growth associated with any size or 
type of load, while excluding any new large loads that PJM knew of and accounted for 
when calculating the initial load forecast.  As such, the Initial RBP Target MW may only 
capture a portion of new load growth, potentially leaving out some new large loads.  This 
could lead to the costs imposed on certain entities not being at least roughly 
commensurate with the benefits they will receive from the procurement.   
As discussed above, while a cost allocation method need not allocate costs with 
“exacting precision,”260 in order to be just and reasonable it must allocate costs in a 
manner that is at least roughly commensurate with benefits.261  We find that a cost 
257 Proposed Tariff, attach. DD, § 18.3(a). 
258 PJM Interconnection, L.L.C., 188 FERC ¶ 61,200, at P 21 (2024). 
259 See, e.g., NJBPU Answer at 3-6.  
260 Coal. of MISO Transmission Customers, 172 FERC ¶ 61,099 at P 83 (quoting 
Midwest ISO Transmission Owners, 373 F.3d at 1369); see also Ill. Com. Comm’n, 576 
F.3d at 477. 
261 Ill. Com. Comm’n, 576 F.3d at 477.

Docket Nos. ER26-3380-000 and EL26-108-000 
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allocation method that results in fixed cost assignments over the 15-year RBP 
commitment period that is based on accurate load forecast information may be just and 
reasonable and consistent with the cost causation principle.  However, PJM has not 
demonstrated that reliance on the Load Adjustment process is just and reasonable.  The 
RBP is a one-time procurement of capacity resources to address a shortfall attributable to 
load growth in certain Electric Distributor zone/areas.  Allocating RBP costs based on a 
snapshot of this shortfall over the term of the RBP commitment period may provide 
greater certainty to the LSEs in the Electric Distributor zone/areas ultimately bearing 
responsibility for those costs.  
Having found that PJM’s proposed method for allocating RBP costs among 
Electric Distributor zone/areas may be unjust and unreasonable, and because we are 
ordering paper hearing procedures to examine a reasonable cost allocation method, we 
decline to further address arguments raised in the protests related to PJM’s proposed cost 
allocation method at this time. 
(e)
PJM’s RBP Proposal May Be Just and 
Reasonable if Modified  
Having found that PJM’s proposed RBP cost allocation method may be unjust and 
unreasonable, and having also initiated an investigation into PJM’s existing Tariff under 
FPA section 206, we now conclude that additional record evidence is needed to 
determine whether PJM’s proposed RBP cost allocation method could be just and 
reasonable if modified.  We therefore establish paper hearing procedures and direct 
further briefing on the issues discussed below.  However, we note that the Commission 
encourages PJM to carefully consider the issues we raise in this order and determine the 
most expeditious path to resolving them.  In particular, we encourage PJM to consider 
swiftly submitting a new FPA section 205 filing without delay.   
While we find that PJM’s proposal to allocate RBP costs based on its Load 
Adjustment process may be unjust and unreasonable, we note that it may be just and 
reasonable for PJM to allocate RBP costs based on updated load forecast information.  
PJM could base the RBP allocation on the difference between the actual load for 
2026/2027 delivery year in each Electric Distributor zone/area with the most recent 
2028/2029 delivery year load forecast for each Electric Distributor zone/area.262  This 
could ensure that the load forecast information on which the allocation relies reasonably 
captures all forecasted load growth.  Such a method for allocating RBP costs among 
Electric Distributor zone/areas may be consistent with the cost causation principle 
because it would appropriately assign RBP costs to the Electric Distributor zone/areas 
262 As an alternative to the use of Load Adjustments, PJM could consider using 
other measures of large load growth or potentially aggregate load growth.

Docket Nos. ER26-3380-000 and EL26-108-000 
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with the reported new load that is driving the need for the procurement.  Similarly, PJM 
should employ the most up-to-date load and resource forecasts to inform the Initial RBP 
Target. 
We reiterate that we encourage PJM to swiftly submit a new section 205 filing 
without delay.  We anticipate that the Commission would grant a motion to hold the 
briefing in this proceeding in abeyance if PJM submitted a new section 205 filing within 
30 days from the date of this order.  However, absent such an FPA section 205 filing, 
initial briefs are due 45 days from the date of this order.  Briefs should address whether 
the above-described method for allocating RBP costs would be just and reasonable.   
We recognize that the rapid emergence of large loads presents a shared regulatory 
challenge that implicates both federal and state authority.  Under the FPA, the 
Commission oversees rates and practices affecting wholesale service, including PJM’s 
procurement of capacity through the RBP.  However, “states determine how 
Commission-approved rates are collected among the relevant retail consumers along with 
the rates for state-jurisdictional matters.”263  Specifically, states have authority over how 
the wholesale costs of providing electricity, including transmission of such electricity to 
the retail customers, are recovered through retail rates.  We are encouraged by the 
NEDC/PJM Governors’ Principles, in which the governors of all 13 PJM states agreed 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 [RBP] to new data center loads that have not otherwise 
procured capacity or agreed to be curtailable.”264  We are also encouraged by the 
execution of the President’s Ratepayer Protection Pledge, through which data center 
developers have committed to shield retail ratepayers from increased electricity prices.265
Our partners in the states are more than capable of ensuring that these promises reach 
fruition.  While we appreciate and take seriously the issues that PJM’s RBP proposal is 
designed to address, as well as the concerns surrounding the unprecedented influx of 
large loads more broadly, having only such powers as are given to us by Congress, we 
263 PJM Interconnection, L.L.C., 195 FERC ¶ 61,211, at P 69 (2026); see also
Transmittal at 106 (quoting the same). 
264 U.S. Department of Energy, Statement of Principles Regarding PJM 2 (Jan. 
2026), https://www.energy.gov/documents/statement-principles-regarding-pjm. 
265 The White House, President Trump’s Ratepayer Protection Pledge Secures 
American AI Dominance, Protects Consumers (July 2026), 
https://www.whitehouse.gov/releases/2026/07/president-trumps-ratepayer-protection-
pledge-secures-american-ai-dominance-protects-consumers/.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 66 - 
will not pretend that all of these issues can be solved exclusively by market design in the 
federal sphere.  The PJM states have their own role to play. 
ii.
Transmission Owner Exit Rules 
(a)
Filing 
PJM proposes to set forth the responsibilities of various parties in the event a 
Transmission Owner exits from PJM.  PJM states that establishing these rules in the RBP 
proposal will provide the requisite notice of how RBP commitments will be honored and 
recognizes that a primary incentive for developers to participate in the RBP is the revenue 
certainty afforded developers through a 15-year commitment.266  PJM’s proposal is 
described below. 
First, if a Transmission Owner exits PJM and committed RBP Resources are 
physically in that Transmission Owner’s service territory, the Transmission Owner may, 
prior to exiting PJM, enter into a separate agreement with the impacted RBP Resources 
that would maintain appropriate rates, terms, and conditions of the RBP commitments.  If 
the exiting Transmission Owner does not enter into such an agreement, PJM proposes to 
require the exiting Transmission Owner to cover all costs necessary for those RBP 
Resources that exceed the Transmission Owner’s withdrawn load to be pseudo-tied back 
into PJM pursuant to Tariff, Attachment DD, section 5.5A, thus allowing such resources 
to continue providing capacity to serve PJM’s load.  PJM states that RBP Resources 
would be exempted from the electrical distance test to allow for such resources to be 
pseudo-tied back into PJM, which will allow such resources to qualify as external 
capacity resources that can continue to serve PJM loads even if such resources are 
physically located beyond the usual electric distance requirement.  In the event PJM does 
not elect to retain such RBP Resource or the resource is unable to be pseudo-tied back 
into PJM, the exiting Transmission Owner would be obligated to pay for the remaining 
term of the RBP Resource’s commitment on an accelerated basis prior to exiting PJM as 
determined through a separate filing with the Commission.267  In the latter two cases, 
PJM states it would pay the collected revenues from the Transmission Owner to the 
impacted RBP Resources. 
Second, if a Transmission Owner withdraws from PJM and net load leaves with 
the Transmission Owner, resulting in stranded committed RBP Resources remaining 
within the PJM Region, PJM similarly proposes to allow such exiting Transmission 
Owner, prior to exiting PJM, to enter into agreements that would maintain appropriate 
rates, terms, and conditions and preserve the RBP commitments with the owners of the 
266 Transmittal at 91. 
267 Id. at 92-94; Proposed Tariff, attach. DD, § 18.7 (0.0.0), § 18.7(a).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 67 - 
RBP Resource(s).  Absent such an agreement, PJM proposes to require the Transmission 
Owner to pay for all forward obligations associated with the net load that was allocated 
RBP Charges, the exact amount which would be determined through a separate filing 
with the Commission.268  PJM argues that this would ensure that the remaining load 
within the PJM Region will not be stranded with increased costs necessary to pay for the 
remaining term of RBP Resources that are not located within the Transmission Owner’s 
service territory.  PJM states that the revenues collected from the Transmission Owner 
and credited to remaining loads will help offset any cost increases to remaining loads that 
may be necessary to continue honoring the commitments of RBP Resources remaining in 
the PJM Region through the rest of the 15-year term.269
PJM states that establishing these rules in the Tariff now avoids any potential 
arguments that changes to cost allocation associated with the RBP Resources after the 
commitments have already made may be impermissibly retroactive.270  PJM adds that 
these rules predominately affect RBP Resources and load commitments, particularly in 
relationship to how they interact with other obligations and assurances provided by 
suppliers and buyers, and are thus properly addressed in the Tariff, as part of the rules 
concerning the RBP framework.271
(b)
Responsive Pleadings 
PPL and Indicated PJM TOs argue that the Transmission Owner exit provisions 
should be placed in the CTOA, not the Tariff, as evidenced by the existing CTOA 
requirements in sections 3.2 and 3.4 governing an exiting Transmission Owner’s 
obligations.272  PPL argues that the Transmission Owner exit provisions predominately 
affect the rights and responsibilities of the PJM Transmission Owners and PJM and 
therefore should be placed in the CTOA.273  Indicated PJM TOs argue that PJM lacked 
268 Transmittal at 94; Proposed Tariff, attach. DD, § 18.7, § 18.7(b). 
269 Transmittal at 94-95. 
270 Id. at 95-96. 
271 Id. at 96 (citing Duquesne Light Co., 189 FERC ¶ 61,181, at P 55 (2024) 
(citations omitted), order addressing arguments raised on reh’g, 192 FERC ¶ 61,051 
(2025)). 
272 PPL Protest at 6; Indicated PJM TOs Protest at 6. 
273 PPL Protest at 4, 7 (citing Duquesne Light Co., 189 FERC ¶ 61,181, at P 55 
(2024); order on reh’g, 192 FERC ¶ 61,051, at P 73 (2025); ISO New Eng. Inc., 106 
FERC ¶ 61,280 (2004) (internal citations omitted)).

Docket Nos. ER26-3380-000 and EL26-108-000 
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authority to file the Transmission Owner exit provisions because they effectively amend 
the CTOA.  Indicated PJM TOs assert that allowing PJM to alter the CTOA’s substance 
simply by casting the change as an OATT amendment would effectively provide PJM 
unilateral discretion to amend the CTOA in clear contravention of section 8.5.1 of the 
CTOA, which requires a supporting vote from the Transmission Owners to amend the 
terms of the CTOA.  Indicated PJM TOs state that if the Transmission Owner exit 
provisions are somehow viewed as imposing transmission-related costs, these provisions 
would fall within the Transmission Owner’s unilateral and exclusive filing rights under 
CTOA section 7.5.1(iv).  Indicated PJM TOs add that, at a minimum, the Transmission 
Owner exit provisions relate to or affect transmission-related costs, and thus PJM was 
required to, but did not, provide the Transmission Owners with 45-days notice of the 
intended filing pursuant to CTOA section 7.5.1(ii).274
In response, PJM argues that the Transmission Owner exit provisions are not 
required to be in the CTOA, as they do not relate to or affect transmission-related 
costs.275
EKPC and AEP similarly argue that the Transmission Owner exit provisions could 
meaningfully and unfairly expand the negotiated terms of exit embedded in the CTOA, 
OA, and RAA.  AEP states that PJM’s governing documents do not contain an exit fee, 
and Commission precedent confirms that a departing member’s obligation with regard to 
generating capacity charges extends only through the last RPM auction in which that 
departing member’s load was included.276  AEP and EKPC request that the Commission 
clarify that any acceptance of these exit provisions is limited to these charges and does 
not undermine existing precedent.277  In response, PJM states that these provisions do not, 
and are not intended to, alter any of the existing responsibilities for Transmission Owners 
that seek to exit PJM.278
EKPC and Indicated PJM TOs assert that the Transmission Owner exit provisions 
are inconsistent with Commission precedent and violate the cost causation principle by 
assigning generation- and capacity-related costs to Transmission Owners rather than to 
LSEs.  Indicated PJM TOs cite to Duquesne Light Company’s (Duquesne) prior planned 
274 Indicated PJM TOs Protest at 2, 4, 6-8. 
275 PJM Answer at 105-106. 
276 See also AEP Answer at 6. 
277 EKPC September 4 Answer at 3, 6; AEP Protest at 10-11, 20, 26-27 (citing 
Duquesne Light Co., 122 FERC ¶ 61,039, at PP 83, 93 (2008) (Duquesne)). 
278 PJM Answer at 102-103.

Docket Nos. ER26-3380-000 and EL26-108-000 
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exit from PJM, under which the Commission found that it was only in the context of 
Duquesne’s role as an LSE pursuant to the RAA that it was responsible for capacity 
charges.  Indicated PJM TOs argue that the Transmission Owner exit provisions violate 
the cost causation principle because Transmission Owners neither cause the costs of 
procuring generation capacity over the RBP’s 15-year term (nor the costs of procuring 
generation capacity under BRAs), nor do they directly benefit from those costs, while 
LSEs and their customers do.279  PJM responds that these provisions are consistent with 
Commission precedent because RBP commitments are established at the time of the RBP 
and are set for 15 years.280
EKPC and AEP assert that these rules are inconsistent with the cost causation 
principle because they would impose an exit fee that could exceed the RBP Charges 
allocated to a departing transmission owner’s zone.  AEP argues that the lack of a 
locational element in RBP undermines the requirement that a departing transmission 
owner assume responsibility for RBP Resources in its zone/area.281  AEP contends that 
this requirement could create an undue barrier to the transmission owner’s ability to 
exercise its right to leave PJM and may result in exit charges that are materially greater 
than the RBP Charges initially allocated to that zone/area.  EKPC contends that requiring 
entities that did not cause RBP to bear costs to pseudo-tie generation into PJM is not 
consistent with cost causation.282
AEP argues that the exit provisions are unjust and unreasonable for failing to 
provide the same contract-for-difference structure to departing transmission owners and 
instead requiring them to fund the full RBP strike price.  AEP asserts that requiring a 
departing transmission owner and its customers to pay more for RBP Charges (with no 
opportunity to offset the charge) than similarly situated load that stays in PJM is unduly 
discriminatory and not tied to the cost causation principle.  AEP contends that this would 
be particularly significant in the event that future load reductions, market changes, or a 
departure of an Electric Distributor or transmission owner result in RBP Resources 
becoming surplus to PJM’s capacity needs.  AEP and EKPC requests that the 
279 EKPC September 4 Answer at 5; Indicated PJM TOs Protest at 2, 10 (citing 
Duquesne 122 FERC ¶ 61,039 at P 83); Indicated PJM TOs Answer at 2-3. 
280 PJM Answer at 103 (citing Duquesne 122 FERC ¶ 61,039; Midwest Indep. 
Transmission Sys. Operator, Inc., 124 FERC ¶ 61,219 (2008)). 
281 EKPC September 4 Answer at 4; AEP Protest at 11, 18. 
282 EKPC September 18 Answer at 10-11.

Docket Nos. ER26-3380-000 and EL26-108-000 
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Commission require PJM to limit a departing Transmission Owner’s liability to the RBP 
Charges allocated to its zone under PJM’s proposed cost allocation method.283
In response, PJM argues that AEP’s arguments fail to appreciate the options 
provided to an exiting Transmission Owner, which mitigate against the argued 
uncertainty.  PJM contends that permitting Transmission Owners to enter into agreements 
with RBP Resources to negotiate appropriate rates, terms, and conditions will allow the 
Transmission Owner to develop cost recovery provisions that it believes are appropriate.  
PJM states that only in the event that the Transmission Owner opts not to enter into an 
agreement must the Transmission Owner pay forward obligations on an accelerated basis, 
which PJM argues is necessary to ensure that the load remaining in PJM is not forced to 
bear the costs of increased RBP Charges.  PJM adds that, even in that instance, the 
Transmission Owner would have the opportunity to advocate for further cost recovery 
through (1) disputing any allocated costs either prior to the filing or once the filing is 
submitted with the Commission, and (2) recovering costs from large loads.  In contrast to 
AEP’s assertion that load outside of PJM is similarly situated to load that stays in PJM, 
PJM argues they are not similarly situated because load that leaves PJM would no longer 
be obligated under the 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.284
AEP, EKPC, and PPL argue that the Transmission Owner exit provisions lack 
sufficient detail and clarity.285  PPL also states that the Transmission Owner exit 
provisions require that the Transmission Owner enter into agreements with RBP 
Resources, but it is unclear how that could be effectuated without coordination between a 
Transmission Owner’s transmission business and generation/marketing business, which 
raises concerns under the Commission’s Standards of Conduct.286  PPL adds that the 
Transmission Owner exit provisions may not apply to every Transmission Owner seeking 
283 AEP Protest at 13-16, 19; EKPC September 4 Answer at 6. 
284 PJM Answer at 99-102 (citing AEP Protest at 14-15). 
285 PPL Protest at 12 (arguing the provisions do not clearly and specifically set 
forth the rates and charges that are to be imposed on an exiting Transmission Owner); 
EKPC September 4 Answer at 5-6 (agreeing with PPL and AEP); AEP Protest at 12-13 
(asserting that (1) it is not clear what is required to pursue a voluntary agreement under 
section 18.7(a); (2) PJM does not explain or justify its request to elect not to retain an 
RBP Resource that can be pseudo-tied back to PJM; (3) it is not clear what contract 
would satisfy section 18.7(b)). 
286 PPL Protest at 7-8 (citing 18 C.F.R. pt. 358 (2025)).

Docket Nos. ER26-3380-000 and EL26-108-000 
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to exit PJM because not all Transmission Owners are LSEs that have executed the RAA, 
in which many of the RBP requirements are located.   
PJM responds that it disagrees with protesters that the proposed Tariff language 
lacks specificity.  PJM states that there is sufficient detail provided in the Tariff 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.  PJM states that, in the 
event a Transmission Owner does exit, there will be extensive negotiations that take place 
with respect to RBP and a variety of other obligations.287  PJM argues that the proposed 
Tariff language in Attachment DD, sections 18.7(a) and 18.7(b) is sufficiently clear that 
the purpose of such agreements is to ensure that the exiting Transmission Owner 
preserves the RBP commitments with the owners of RBP Resources.288  With respect to 
concerns that PJM may elect to retain an RBP Resource as a capacity resource, PJM 
contends that it must retain the discretion necessary to ensure resource adequacy and 
reliability, including the ability to consider the topology of the transmission system at the 
time of the desired exit.  With respect to arguments concerning the requisite Commission 
filing and costs, PJM argues that final cost determinations are appropriately decided at 
the time of the Transmission Owner’s exit because it is impossible to determine what 
those circumstances will be.  In response, AEP argues that PJM’s answer is unresponsive 
to its concerns and would ultimately afford PJM considerable discretion over a 
Transmission Owner’s ability to withdraw.289
PJM also disputes that the proposed Tariff revisions violate the separation of 
functions requirements of the Commission.  PJM states that the proposed requirements 
are merely intended to honor obligations that would have pre-existed the exit of a 
Transmission Owner from PJM.  PJM adds that activity that may otherwise violate 
separation of functions is permissible, pursuant to 18 C.F.R. § §358.2(d), § 358.1(d) 
(2025), respectively, where ordered by the Commission or where the Commission has 
granted waiver of such requirements.290
287 PJM Answer at 95-96. 
288 Id. (citing PJM, Intra-PJM Tariffs, ATTACHMENT DD.18.7, 
ATTACHMENT DD.18.7 Exiting Transmission Owner RBP Obligation (0.0.0)). 
289 AEP Answer at 4-5. 
290 Id. at 106-107.

Docket Nos. ER26-3380-000 and EL26-108-000 
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EKPC and PPL argue that the Commission need not address this issue 
preemptively, particularly given the absence of any pending withdrawal requests and 
PJM’s own acknowledgement that the possibility of this contingency is “remote.”291
(c)
PJM’s Proposal May Be Unjust and 
Unreasonable 
We find that, as proposed, the Transmission Owner exit provisions may be unjust 
and unreasonable.   
As protesters note, the Commission has previously found that it is just and 
reasonable to impose generation capacity costs on LSEs located within an exiting 
Transmission Owner’s zone.292  In Duquesne, the Commission assessed a withdrawing 
LSE’s RPM obligations and noted that “[u]nder RPM, PJM is responsible for procuring 
capacity on behalf of LSEs in each zone three years in advance based on the auction 
results, and PJM’s obligation to pay the generators is fixed at the time of the auction.”293
The Commission stated that “Duquesne understood that PJM was procuring capacity on 
its behalf and therefore should be obligated to pay for that capacity.”294  Under its RBP 
proposal, PJM similarly proposes to procure capacity through the RBP on behalf of 
LSEs, establish obligations to pay RBP Resources at the time of the procurement, and 
later allocate those costs to LSEs.  PJM fails to explain why Transmission Owners—who 
are not the buyers for which PJM procures capacity under the RBP—should be 
responsible for RBP Charges.   
Based on the current record, it appears that the proposed Transmission Owner exit 
provisions may be inconsistent with the cost causation principle because they do not 
assign costs to the entities that cause the costs and benefit from the capacity procurement 
under the RBP, i.e., LSEs.  As explained in Section IV.B.3.a.i(d) above, under 
the cost causation principle, all Commission-jurisdictional rates and charges must “reflect 
to some degree the costs actually caused by the customer who must pay for them,”295 and 
291 PPL Protest at 10 (citing Transmittal at 91 (internal citations omitted)); EKPC 
September 4 Answer at 7. 
292 Duquesne 122 FERC ¶ 61,039 at PP 89-94 (2008).  See Indicated PJM TOs 
Protest at 8-10; EKPC September 4 Answer at 5. 
293 Duquesne, 122 FERC ¶ 61,039 at P 89.   
294 Id.
295 KN Energy Inc. v. FERC, 968 F.2d at 1300; see also Ky. Comm’n, 193 FERC 
¶ 61,110.

Docket Nos. ER26-3380-000 and EL26-108-000 
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costs must be allocated in a manner that is at least roughly commensurate with 
benefits.296  Here, it appears that PJM has not demonstrated that the proposed obligations 
and “exit fees” associated with RBP costs—which PJM proposes to impose on the exiting 
Transmission Owner—reflect the benefits that the RBP will provide.  PJM’s RBP 
proposal is necessary to address capacity shortfalls in the PJM Region, and the 
beneficiaries of the RBP are the LSEs on whose behalf PJM will procure capacity 
through the RBP.  Therefore, we find that PJM’s proposed exit provisions may be unjust 
and unreasonable because they would assess RBP Charges to exiting Transmission 
Owners, rather than the LSEs in the relevant Transmission Owner’s zone.   
However, we disagree with protesters that establishing exit provisions in the Tariff 
would unnecessarily constrain the parties involved in effectuating a Transmission 
Owner’s withdrawal from PJM.  As PJM states, the cost obligations will be 
“appropriately decided at the time of Transmission Owner’s exit and subject to 
Commission approval.”297
(d)
PJM’s RBP Proposal May Be Just and 
Reasonable if Modified 
As a general matter, we recognize that it may be just and reasonable to have 
provisions to protect against cost shifts should a Transmission Owner exit PJM during the 
RBP term (i.e., before the end of the 2042/2043 delivery year).  As discussed above, the 
Commission has found that a withdrawing LSE’s obligations under the RAA and 
Attachment DD of the Tariff may include capacity costs.298  Similar to the costs of 
capacity that PJM procures through its RPM Auctions, PJM here proposes to allocate the 
costs of procuring capacity through the RBP to LSEs.  Therefore, a just and reasonable 
approach could require LSEs in an exiting Transmission Owner’s zone to pay RBP exit 
fees commensurate with their cost allocation under the RBP, to prevent cost shifts to 
other LSEs in the PJM Region.  As PJM proposes, exit provisions could still leave 
flexibility for LSEs to enter into agreements with RBP Resources (which they may need 
to serve their load) or pay to pseudo-tie RBP Resources located within the exiting 
Transmission Owner’s zone back into PJM.   
As discussed elsewhere, we conclude that additional record evidence is needed to 
determine a just and reasonable approach to preventing RBP cost shifts should a 
Transmission Owner exit PJM before the end of the 2042/2043 delivery year (i.e., the 
completion of the term of RBP Resources’ commitments).  Among other topics, the 
296 See, e.g., Ill. Com. Comm’n, 576 F.3d at 477. 
297 PJM Answer at 98. 
298 Duquesne, 122 FERC ¶ 61,039 at PP 86, 90-91.

Docket Nos. ER26-3380-000 and EL26-108-000 
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Commission directs further briefing on whether (1) it would be appropriate for LSEs in 
an exiting Transmission Owner’s zone to be responsible for RBP exit charges, rather than 
the Transmission Owner, and (2) it would be just and reasonable to assign LSEs RBP exit 
charges based on the cost of capacity that PJM procures through the RBP on behalf of 
LSEs in a Transmission Owner’s zone, i.e., the LSE’s cost allocation under the RBP. 
iii.
LSE Collateral Requirement 
(a)
Filing 
PJM proposes to require both RBP Sellers and buyers of RBP UCAP MW (i.e., 
LSEs) to provide collateral.299  The collateral for RBP Sellers, required to be posted at the 
time of the auction, reflects three years of RBP UCAP MW shortfall charges for that 
resource.  PJM returns the collateral when an RBP Resource no longer gives rise to credit 
exposure (e.g., after the resource fails to clear).  The RBP collateral requirement for LSEs 
is the product of the RBP Credit Rate and the total RBP MW committed.  PJM explains 
that the initial RBP Credit Rate of $1.5 million ensures that PJM holds sufficient 
collateral to cover about 50% of the notional value of all RBP commitments.300  PJM 
proposes to require that LSEs post collateral 45 days before the first delivery year in 
which RBP Resources are expected to be in service (i.e., 2028/2029), and that the 
collateral be returned as financial exposure lessens.  Citing elevated risks in the current 
marketplace, PJM also proposes strict criteria for acceptable collateral.  PJM states that, 
“like the credit requirements imposed on inherently riskier Financial Transmission 
Rights,” sellers and buyers of RBP UCAP MW are limited to providing RBP Collateral 
in the form of either a cash deposit or Letter of Credit.
If an LSE defaults and fails to pay an RBP Charge, the defaulted amount is 
reallocated to all remaining LSEs responsible for paying RBP Charges based on their pro 
rata share of the total RBP Charges for all such LSEs.301  Such amounts may be offset by 
the RBP Collateral posted by the defaulting LSE.  If an RBP Resource defaults on 
payment of RBP shortfall charges, the corresponding credits are not allocated to the LSEs 
that would otherwise receive them.302
299 Proposed Tariff, attach. DD, § 18.8. 
300 Transmittal at 116, 109-110, 120. 
301 Proposed Tariff, attach. DD, § 18.9(a). 
302 Proposed Tariff, attach. DD, § 18.9(b).

Docket Nos. ER26-3380-000 and EL26-108-000 
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(b)
Responsive Pleadings 
Parties contest both the proposed RBP Collateral requirement for LSEs and the 
proposed criteria for acceptable collateral.  FirstEnergy, for example, faults PJM’s 
proposal for several reasons, arguing that PJM’s filing lacks the support typically 
provided for credit requirements.  FirstEnergy also faults PJM’s proposal for assuming all 
classes of LSEs present the same credit risk, regardless of whether they have regulated 
cost recovery.  FirstEnergy contends that the proposal is also unduly discriminatory 
because under similar Public Utility Regulatory Policies Act contracts, the purchasing 
entities generally have been subject to low or no collateral requirements because of their 
ability to recover costs from retail customers.303
EKPC argues that PJM has not linked the RBP collateral requirement to exposure, 
as evidenced by (1) the timing gap between when the exposure is identified and when the 
collateral is required and (2) the misalignment between the buyer collateral requirement 
and the seller collateral requirement.304  EKPC contends that PJM’s proposal would result 
in the same obligation being collateralized twice, once under RBP and once under 
Attachment Q of its existing Tariff.  EKPC argues that it is also unjust and unreasonable 
to require LSEs to post collateral prior to the finalization of the cost allocation because it 
does not provide LSEs with sufficient transparency and time to challenge the 
obligation.305  EKPC asserts that it is not just and reasonable to concentrate the collateral 
requirements among LSEs that receive RBOs because this creates system liquidity risk.306
SMECO notes that LSEs could have as few as 15 days from the time they learn 
their final collateral requirement to the deadline to post that collateral.307  This is the case 
because the deadline for Electric Distributors to report RBO allocations is 60 days before 
the delivery year, while the collateral deadline is 45 days before the same delivery year. 
Equinix argues that the RBP Collateral requirement for LSEs is not just and 
reasonable for three reasons.  First, Equinix asserts that the collateral requirements are 
303 FirstEnergy Protest at 8-9. 
304 EKPC Protest at 22-23 (citing NOVEC Protest, attach. 2 (Affidavit of Carl F. 
Coscia) ¶¶ 203, 204 (Coscia Aff.)). 
305 Id. at 24. 
306 Id. at 27. 
307 SMECO Comments at 7; see also Constellation Protest at 16 (“That [15-day] 
period is not reasonably practicable and creates an unnecessary risk of credit default and 
resulting cost reallocation.”).

Docket Nos. ER26-3380-000 and EL26-108-000 
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disproportionate and inconsistent because sellers have the most control over risks of 
development and non-performance but have lower collateral requirements than buyers.  
Second, Equinix disagrees with PJM that RBP exposure is analogous to FTR exposure 
because the latter is volatile while RBP Charges are fixed in advance, which is similar to 
the risk PJM manages under Attachment Q of its existing Tariff.  Third, Equinix argues 
that the collateral requirement does not protect ratepayers because it will require LSEs to 
finance the posting of the collateral, which will materially raise rates.  Equinix requests 
that the Commission modify the proposed buyer-side RBP Collateral provisions so that 
collateral is calibrated to reasonably foreseeable forward exposure and the forms of credit 
support available under Attachment Q are permitted.308
NOVEC argues that its highest possible collateral requirement, estimated to be 
about $1.95 billion, would exceed NOVEC’s total assets and disrupt NOVEC’s ordinary 
business operations.  NOVEC adds that it is uncertain whether it would even be able to 
secure $2 billion in collateral.  NOVEC argues that PJM’s proposal to require the 
collateral obligation of the buyers to span the entire 15-year period is not necessary, as 
the risk could be significantly mitigated by a shorter period, such as three years.  NOVEC 
contends that the most significant obstacle to NOVEC fulfilling its RBP obligations is the 
size of the RBP collateral obligation itself and not the RBP Charges.  NOVEC notes that 
PJM’s proposal limits the RBP Sellers’ collateral obligation to three years to avoid 
making the collateral requirement “onerous.”309
NOVEC and Constellation also take issue with the assumptions PJM makes when 
calculating the initial RBP Credit Rate of $1.5 million.310  NOVEC and Constellation 
argue that PJM’s calculation assumes that RBP buyers have to collateralize the entire 
$555/MW-day, when the RBP Charges will be the RBP clearing-price average (which 
can be less than $555/MW-day) net of revenues from the capacity auction.311  EKPC and 
Constellation aver that PJM has sized collateral as though load owed the full contract 
price, when the Tariff obligates load to pay only a difference between two prices under 
308 Equinix Comments at 2,6, 15-16; see also SMECO Comments at 2, 8 (claiming 
that the LSEs’ collateral requirement is 14.5 times the size of the requirement for sellers). 
309 NOVEC Protest at 20 (citing NOVEC Protest, attach. (Affidavit of Wilbur 
Rollins) at 2-3).  See also EKPC Protest at 13 (arguing that requiring so much collateral 
at once creates a systemic liquidity risk). 
310 Id. at 21 (citing Coscia Aff. ¶¶ 38, 46); Constellation September 8 Answer at 5-
6. 
311 NOVEC Protest at 21; Constellation September 8 Answer at 6-7.  See also
EKPC Protest at 25.

Docket Nos. ER26-3380-000 and EL26-108-000 
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the contract for differences approach.312  Effectively, NOVEC argues, RBP buyers are 
providing collateral to ensure that everyone in PJM pays the capacity costs associated 
with the RBP Resources.  NOVEC notes that RBP buyers themselves already provide 
PJM collateral to ensure that they pay their capacity rates under Attachment Q, and so do 
all other capacity buyers.313  NOVEC argues that PJM is thus requiring duplicative 
collateral.  Constellation also expresses concerns that (1) the credit rate relies on 15 years 
of gross contract value rather than the net RBP Charges that LSEs will be billed; (2) the 
Tariff does not identify the time needed to draw collateral and reallocate any residual 
default, or the stress assumptions used to estimate net exposure; (3) it applies the same 
$1.5 million/MW base rate without explaining why credit quality may increase—but 
never reduce—the base requirement; and (4) the Tariff establishes no mandatory 
recalculation schedule, prescribed inputs, or objective collateral-release standard.314
NOVEC further argues that the proposed Tariff provision is ambiguous as to when 
the collateral obligation will be reduced and does not appear to properly reduce it over 
time.  NOVEC notes that according to the proposed Tariff provision, “the 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.”  NOVEC 
argues that PJM should not have the discretion to determine whether RBP buyers should 
be required to post more collateral than the total existing RBP obligations, especially 
given that the calculation already overstates the likely RBP Charges.  NOVEC further 
argues that there are too few circumstances in which the collateral obligation is reduced.  
According to NOVEC, if PJM believes that 50% of the total payment obligations at the 
start of the 15-year term is sufficient, then the same percentage of the total remaining 
payment obligations should be the cap for each year.315
AEP asks the Commission to direct PJM to clarify that collateral obligations attach 
only to LSEs allocated responsibility for RBP Charges, not to Electric Distributors acting 
solely in an administrative or delivery-service role.  AEP argues that this clarification 
would be consistent with PJM’s statement that RBP Buyer collateral is intended to 
mitigate the risk of non-payment of RBP Charges and that only LSEs allocated 
312 EKPC Protest at 25; Constellation September 8 Answer at 6-7. 
313 NOVEC Protest at 21 (citing Coscia Aff. ¶ 26). 
314 Constellation September 8 Answer at 6. 
315 NOVEC Protest at 22, 23 (citing Proposed Tariff, § 18.8(b)(i)(A) (emphasis 
added)). See also FirstEnergy Protest at 9 (criticizing PJM’s proposal to retain absolute 
discretion on how quickly it returns excess collateral).

Docket Nos. ER26-3380-000 and EL26-108-000 
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responsibility for RBP Charges generally will have a credit requirement.  AEP further 
argues it would be inconsistent with the cost causation principle to improperly shift credit 
risk from the entities serving and benefiting from the load to an Electric Distributor that 
neither controls generation supply decisions nor receives the revenues associated with 
serving that load.316
PPL states that it understands that if there are no RBOs reported to PJM for an 
Electric Distributor zone/area with RBP UCAP MW assigned, or if there are “stranded” 
RBOs, then the credit requirements will move to all LSEs in the zone/area based on Peak 
Load Contributions.  Presumably, PPL continues, once credit requirements are assigned 
based on Peak Load Contributions, RBP Charges will also flow to those LSEs.  EKPC 
and PPL are concerned that this scenario could result in LSEs that do not serve large 
loads receiving these obligations, thereby having nowhere to assign them except to other 
customers.317  EKPC, ODEC, and PPL request that PJM clarify that if an LSE defaults 
and fails to pay an RBP Charge, whether the defaulted amount will be allocated to all 
remaining LSEs in the Electric Distributer zone/area or to all LSEs in the PJM Region.318
Constellation recommends that large load customers be permitted to post collateral 
for the responsible LSE to avoid unnecessary intermediation through the LSE and 
duplicative credit postings.319  Constellation states that the record is not sufficiently 
developed to prescribe a durable collateral methodology and requests that the 
Commission establish an expedited paper hearing on the matter.320
(c)
Answers 
PJM argues that 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 allocated cost responsibility for RBP Resources from 
having to pay for such resources.321
316 AEP Protest at 33-34. 
317 EKPC Protest at 28; PPL Protest at 13. 
318 EKPC September 18 Answer at 12, 16; PPL Protest at 13; ODEC Comments at 
10. 
319 Constellation September 8 Answer at 8. 
320 Id. at 9-10. 
321 PJM Answer at 74-75.

Docket Nos. ER26-3380-000 and EL26-108-000 
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In response to protesters’ claims that the proposed LSE collateral requirement is 
duplicative of exiting PJM credit rules, PJM argues that its existing requirements (i.e., 
Peak Market Activity collateral) serve a different purpose and tracks different types of 
financial exposure than the proposed RBP credit requirement.322  PJM states that the Peak 
Market Activity metric manages immediate, rolling operational risk from daily 
transactions based upon a rolling, backward-looking billing history, 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 states that the proposed RBP 
credit requirement is to cover forward-looking risk over a long-term, up-to-15-year 
commitment to sellers.  PJM also argues that an LSE’s obligation to pay RBP Charges 
should not be shunted to a provider of last resort because the large load driving the need 
for RBP should bear these costs. 
In response, NOVEC maintains PJM’s proposal does require suppliers to provide 
duplicative collateral because PJM proposes to determine RBP collateral obligations as if 
suppliers were paying the entire RBP Charge—which means suppliers are providing 
collateral for the cost of capacity of their RBP MW and providing collateral for the RBP 
clearing price, and not just for the difference between the RBP price and the capacity 
clearing price.323
Regarding protests that the credit requirements should be tailored to the credit risk 
presented by specific LSEs, PJM states that it looked at the forward obligation to the RBP 
Resources instead of individual LSE’s creditworthiness because (1) it better safeguards 
the payment and reduces exposure in case of default, (2) it allows for a uniform credit 
rate applicable to each allocated MW, which ensures non-discriminatory requirements for 
all LSEs, and (3) creditworthiness of individual LSEs may change considerably during a 
15-year term.324
In response, NOVEC argues that PJM overstates the risk of declining 
creditworthiness because the RBP Charges that NOVEC could be responsible for 
represent, in any given year, a tiny fraction of the collateral PJM would require NOVEC 
to post.325  NOVEC therefore argues that the greatest threat to NOVEC’s credit rating is 
PJM’s own RBP collateral requirement.   
322 Id. at 78. 
323 NOVEC Answer at 16-17. 
324 PJM Answer at 80-81. 
325 NOVEC Answer at 18.

Docket Nos. ER26-3380-000 and EL26-108-000 
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In response to protesters’ claims that the credit requirements are excessive, PJM 
argues that the credit requirements are 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.  PJM 
asserts its approach is consistent with Commission policy because it reasonably balances 
protecting PJM’s members against the risk of default and appropriately correlating the 
credit requirement with the risk level.326  PJM adds that it limited the forms of collateral 
to letters of credit and cash because it determined there would likely not be sufficient 
unsecured credit available from these LSEs to cover the up-to-15-year forward credit 
obligation.  PJM argues that the initial RBP Credit Rate of $1.5 million per RBP UCAP 
MW is just and reasonable and supported because it 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.327  PJM contends that this represents approximately 50% of a 
quantifiable potential contractual exposure, rather than full collateralization, and can 
decline as the remaining exposure declines, which undermines claims that the amount is 
excessive or insufficiently correlated to credit risk.  PJM argues that protesters ignore the 
fact that standard business practices for LSEs signing up new large loads include 
requiring collateral.328
PJM clarifies that the LSE collateral requirement for a delivery year is based only 
on RBP UCAP MW committed for that delivery year and that “no collateral would be 
required for RBP Resources [that] are not in service for that Delivery Year, and no RBP 
Charges would be assessed.”329  In response, NOVEC argues that PJM’s interpretation 
relies on the meaning of the term “committed” used in proposed Tariff, section 
326 PJM Answer at 84 (citing PJM Interconnection, L.L.C., 186 FERC ¶ 61,055, at 
PP 27-28 (2024) (internal citation omitted)). 
327 Id. at 88. 
328 Id. at 88-92.  PPL responds that PJM’s reliance on PPL’s Rate Schedule LP-6 
as an example in its answer is misplaced and inaccurate.  PPL states that this rate 
schedule relates only to its role as an Electric Distribution Company, not an LSE, and 
does not relate to PPL’s role or obligations as an LSE nor any security or collateral that 
may be required to satisfy RBP credit obligations.  PPL Answer at 2-3.  NOVEC 
similarly argues that PJM’s assertion that NOVEC could use its existing collateral 
obligations with its customers is immaterial to the question of whether the proposed RBP 
collateral requirements are just and reasonable.  NOVEC Answer at 20. 
329 PJM Answer at 78 n.234.

Docket Nos. ER26-3380-000 and EL26-108-000 
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18.8(b)(i)(A).330  NOVEC points out that proposed section 18.6(e) permits a resource to 
remain “committed” for up to three delivery years, and proposed section 18.8(b)(i)(A) 
does not have an “in-service” limitation, creating the risk that NOVEC could post 
collateral for an RBP Resource that does not operate during those three delivery years.  
NOVEC asks the Commission to require PJM to revise this section to state that LSEs 
with RBP obligations will not be required to post collateral for RBP Resources that are 
not in service.   
PJM states that, while it has proposed a just and reasonable approach to 
determining the proper buyer-side LSE RBP credit requirement, it also consents to a 
modified approach where the credit rate is 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 maximum of such value.331  PJM states that it would consent to the 
Commission resolving the applicable buyer-side LSE RBP Credit Rate through additional 
procedures.332
(d)
PJM’s Proposal May Be Unjust and 
Unreasonable 
First, although it is related to the broader topic of RBP Collateral, we find PJM’s 
proposed collateral requirements for RBP Sellers just and reasonable, and thus we do not 
include that aspect of the proposal in the list of topics that will be the subject of the paper 
hearing procedures established in this order.  Specifically, PJM’s proposed collateral 
requirements for RBP Sellers are just and reasonable because they will reduce the risks to 
PJM markets associated with non-payment of RBP Shortfall Charges without posing an 
unreasonable barrier to market participation.    
However, we find that the proposed RBP Collateral requirement for LSEs (i.e., 
LSE Collateral requirement) may be unjust and unreasonable.   
330 NOVEC Answer at 21. 
331 PJM Answer at 92-93 (citing NOVEC Protest at 22).  
332 Constellation states that it supports PJM’s proposal to resolve the credit and 
collateral issues through additional procedures.  Constellation September 21 Answer at 9.  
EKPC states that any further proceeding must define the exposure being secured, the 
quantity to which the rate applies, the date on which the obligation arises, objective 
reduction and release standards, the interaction with OA section 15.2.2, and the liquidity 
and default consequences created by the requirement.  EKPC September 18 Answer at 
12.

Docket Nos. ER26-3380-000 and EL26-108-000 
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PJM proposed an initial credit rate of $1.5 million per committed RBP MW 
because it would collateralize approximately 50% of the estimated contractual value 
associated with RBP commitments.  However, as FirstEnergy notes, PJM does not 
support its 50% estimate with any quantitative measures, including an expected 
probability of default, a loss-given-default assumption, a historical LSE default 
experience, a liquidation or replacement period, or any other quantitative measure.333
PJM also fails to demonstrate how the LSE Collateral requirements strike 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.334  PJM otherwise provides little flexibility for LSEs to manage their 
collateral requirements, including a short timeline for posting collateral335 and limited, 
acceptable forms of collateral.  Taken together, we find that PJM’s proposed LSE 
Collateral requirements may be unjust and unreasonable because they do not strike 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. 
(e)
PJM’s RBP Proposal May Be Just and 
Reasonable if Modified 
We find that additional record evidence is needed to determine if PJM’s proposed 
LSE Collateral requirement is just and reasonable.  Therefore, as discussed elsewhere, we 
establish paper hearing procedures and further briefing on appropriate collateral 
requirements for RBP buyers.  As part of their responses, parties should address (1) what 
initial RBP Credit Rate is appropriate and (2) whether 45 days before the start of the 
delivery year is sufficient time for LSEs to post collateral. 
333 FirstEnergy Protest at 9. 
334 See PJM Interconnection, L.L.C., 186 FERC ¶ 61,055 at P 29 (finding PJM’s 
proposed changes to its Peak Market Activity credit calculation strike 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). 
335 See SMECO Comments at 7 (“PJM proposes that the Electric Distributor’s 
RBO allocation be reported at no later than sixty days before the start of the [delivery 
year]; PJM proposes to require the affected LSE to post the resulting collateral just fifteen 
days later, at forty-five days before the [delivery year] begins.  That leaves just a fifteen-
day window to arrange collateral for an obligation whose amount it could not have 
predicted in advance, using a $1.5 million/MW RBP Credit Rate.”).

Docket Nos. ER26-3380-000 and EL26-108-000 
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iv.
Miscellaneous 
(a)
Timing Requirements 
(1)
Filing 
PJM states that the RBP procurement window will open if and when a 
Commission order accepts PJM’s proposed RBP framework.  PJM states that, 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, 2026.336
(2)
PJM’s Proposal May Be Unjust and 
Unreasonable 
As discussed above in Section IV.B, we accept PJM’s proposal for filing and 
suspend it for five months to become effective February 28, 2027, subject to refund and 
to the outcome of paper hearing procedures.  Because we are suspending the tariff 
records for five months, we find that PJM’s tariff records that propose actions during the 
suspension window may be unjust and unreasonable.  For example, the proposed Tariff 
provides that the closing date of the bid solicitation for RBP is in October 2026.337
(3)
PJM’s RBP Proposal May Be Just and 
Reasonable if Modified 
We find that it may be just and reasonable to revise any deadlines set forth in the 
tariff records in accordance with the Commission’s action to suspend the tariff records 
for five months.   
(b)
RAA, Schedule 8.1D, Section 1.1 
(1)
Filing and Responsive Pleadings 
PJM’s proposed tariff revisions state that “[a]n 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.”338
336 Transmittal at 3 n.5. 
337 Proposed Tariff, attach. DD, § 18.5(f). 
338 Proposed RAA, Schedule 8.1D, § 1.1.

Docket Nos. ER26-3380-000 and EL26-108-000 
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AEP and EKPC note that this provision appears to be a drafting error.  They argue 
this provision would unreasonably disallow FRR Entities from using both owned and 
contracted resources.339
In response, PJM states that it inadvertently submitted this revision and did not 
intend to include this revision as part of the RBP proposal.  PJM requests that the 
Commission reject this revised tariff record.340
(2)
Determination 
In accordance with PJM’s request to reject this inadvertently submitted tariff 
record, we reject PJM’s proposed tariff revisions to RAA, Schedule 8.1D, section 1.1. 
4.
EL26-108-000 
As stated earlier, we are establishing a new FPA section 206 proceeding in Docket 
No. EL26-108-000.  In cases where, as here, the Commission institutes a section 206 
investigation on its own motion, section 206(b) of the FPA requires that the Commission 
establish a refund effective date that is no earlier than the date of publication by the 
Commission of notice of its intention to initiate such proceeding nor later than five 
months after the publication date.  In such cases, in order to give maximum protection to 
customers, and consistent with our precedent, we have historically tended to establish the 
section 206 refund effective date at the earliest date allowed by section 206, and we do so 
here as well.341  That date is the date of publication of notice of initiation of the section 
206 proceeding in Docket No. EL26-108-000 in the Federal Register. 
Section 206(b) of the FPA also requires that, if no final decision is rendered by the 
conclusion of the180-day period commencing upon initiation of the section 206 
proceeding, the Commission shall state the reason why it has failed to render such a 
decision and state its best estimate as to when it reasonably expects to make such a 
decision.  As we are setting the section 206 proceeding in Docket No. EL26-108-000 for 
further proceedings, we expect that we would be able to render a decision within five 
months of the date of this order.   
The Commission orders: 
339 AEP Protest at 34-35; EKPC Protest at 47. 
340 PJM Answer at 55 n.160. 
341 See, e.g., Idaho Power Co., 145 FERC ¶ 61,122 (2013); Canal Elec. Co., 46 
FERC ¶ 61,153, order on reh’g, 47 FERC ¶ 61,275 (1989).

Docket Nos. ER26-3380-000 and EL26-108-000 
- 85 - 
(A) PJM’s proposed Tariff and RAA revisions are hereby accepted for filing, 
suspended for five months, effective February 28, 2027, subject to refund and the 
outcome of the further procedures ordered in this proceeding, as discussed in the body of 
this order. 
(B) Paper hearing procedures are hereby established to address issues raised by 
certain aspects of PJM’s proposal, as discussed in the body of this order. 
(C) Pursuant to the authority contained in and subject to the jurisdiction conferred 
upon the Federal Energy Regulatory Commission by section 402(a) of the Department of 
Energy Organization Act and the FPA, particularly section 206 thereof, and pursuant to 
the Commission’s Rules of Practice and Procedure and the regulations under the FPA (18 
C.F.R. Chapter I), the Commission hereby institutes a proceeding in Docket No. EL26-
108-000 concerning the justness and reasonableness of PJM’s tariff, as discussed in the 
body of this order.  
(D) The Secretary shall promptly publish in the Federal Register a notice of the 
Commission’s initiation of the proceeding under section 206 of the FPA in Docket No. 
EL26-108-000. 
(E) The refund effective date in Docket No. EL26-108-000 established pursuant to 
section 206 of the FPA shall be the date of publication in the Federal Register of the 
notice discussed in Ordering Paragraph (D) above. 
By the Commission.  Chairman Swett is concurring with a separate statement attached. 
                                   Commissioner Rosner is concurring with a separate statement  
                                   attached. 
                                   Commissioner See is concurring with a separate statement attached. 
                                   Commissioner LaCerte is concurring with a separate statement  
                                   attached. 
( S E A L ) 
Debbie-Anne A. Reese, 
Secretary.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 86 - 
Appendix A – Tariff Records 
PJM Interconnection, L.L.C. 
Intra-PJM Tariffs 
x
C-D, OATT Definitions – C-D (47.0.0)
x
E-F, OATT Definitions - E - F (45.0.0)
x
O-P-Q, OATT Definitions - O - P - Q (39.0.0)
x
R-S, OATT Definitions – R - S (47.0.0)
x
ATTACHMENT DD.5.5, OATT ATTACHMENT DD.5.5 Eligibility for 
Participation in RPM (7.0.0)
x
ATTACHMENT DD.5.5A, OATT ATTACHMENT DD.5.5A Capacity Resource 
Types (13.0.0)
x
OATT ATT DD.5.14, OATT ATTACHMENT DD.5.14 Clearing Prices and Charges 
(45.0.0)
x
OATT ATT DD.6.6, OATT ATTACHMENT DD.6.6 Offer Requirement for Capacity 
Resour (4.0.0)
x
OATT ATT DD.6.6A, OATT ATTACHMENT DD.6.6A Offer Requirement for 
Capacity Perfo (6.0.0)
x
ATTACHMENT DD.16, OATT ATTACHMENT DD.16. RELIABILITY 
BACKSTOP (3.0.0)
x
ATTACHMENT DD.18, OATT ATTACHMENT DD.18 RELIABILITY 
BACKSTOP PROCUREMENT (0.0.0)
x
ATTACHMENT DD.18.1, ATTACHMENT DD.18.1 Determination of Final RBP 
Target (0.0.0)
x
ATTACHMENT DD.18.2, ATTACHMENT DD.18.2 Qualifying New UCAP MW 
(0.0.0)
x
ATTACHMENT DD.18.3, ATTACHMENT DD.18.3 Cost Allocation of RBP 
Charges, Credits (0.0.0)

Docket Nos. ER26-3380-000 and EL26-108-000 
- 87 - 
x
ATTACHMENT DD.18.4, ATTACHMENT DD.18.4 Scope of the Reliability 
Backstop Procure (0.0.0)
x
ATTACHMENT DD.18.5, ATTACHMENT DD.18.5 The Reliability Backstop 
Procurement Proc (0.0.0)
x
ATTACHMENT DD.18.6, ATTACHMENT DD.18.6 RBP Resource Obligations 
(0.0.0)
x
ATTACHMENT DD.18.7, ATTACHMENT DD.18.7 Exiting Transmission Owner 
RBP Obligation (0.0.0)
x
ATTACHMENT DD.18.8, ATTACHMENT DD.18.8 Credit Requirements for RBP 
Sellers (0.0.0)
x
ATTACHMENT DD.18.9, ATTACHMENT DD.18.9 RBP Default Allocation (0.0.0)
x
RAA ARTICLE 1, RAA ARTICLE 1 -- DEFINITIONS (56.0.0)
x
RAA Article 7 Sec 2B, RAA Article 7 Sec 2B Responsibility to Pay RBP Charges 
(0.0.0)
x
RAA Article 7 Sec 2C, RAA Article 7 Sec 2C Provision of RBP Obligations (0.0.0)

Docket Nos. ER26-3380-000 and EL26-108-000 
- 88 - 
Appendix B – Intervenors 
*Filed Comments 
Advanced Energy United (AEU)* 
Amazon Energy LLC (Amazon)* 
Ameren Services Company 
American Council on Renewable Energy 
American Electric Power Service Corporation (AEP)* 
American Municipal Power, Inc. (AMP)* 
Appalachian Voices 
Avangrid Networks, Inc. 
Avangrid Power, LLC (Avangrid, collectively with Avangrid Networks, Inc.) 
Base Power Inc. (Base Power)* 
Blue Ridge Power Agency (Blue Ridge)* 
Boston Energy Trading and Marketing LLC 
Brookfield Renewable Trading and Marketing LP 
Buckeye Power, Inc. 
Calibrant Energy (Calibrant)* 
Citizens’ Electric Company of Lewisburg, PA 
Consolidated Edison Company of New York, Inc. (ConEd)342
Constellation Energy Generation, LLC (Constellation)* 
CPV Power Holdings, LP (CPV)* 
CyrusOne LP 
Data Center Coalition (DCC)* 
Delaware Division of the Public Advocate*343
Dominion Energy Services, Inc. (Dominion)* 
Duke Energy Corporation 
Duquesne Light Company (Duquesne) (Indicated PJM Transmission Owners (Indicated 
PJM TOs), collectively with FirstEnergy Transmission Companies)* 
E-Cubed Policy Associates, LLC (E-Cubed)* 
East Kentucky Power Cooperative, Inc. (EKPC)* 
EDF Power Solutions, Inc. 
Edison Electric Institute 
Electric Power Supply Association 
342 ConEd filed two motions to intervene, one out-of-time. 
343  Delaware Division of the Public Advocate, District of Columbia Office of 
People’s Counsel, Illinois Citizens Utility Board, Office of the Illinois Attorney General, 
Maryland Office of the People’s Counsel, and New Jersey Division of Rate Counsel 
(collectively, Joint Consumer Advocates (JCA)) submitted a joint protest.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 89 - 
Enel X North America, Inc. 
Energy LLC 
Energy Trading Institute 
ENGIE North America Inc. 
Equinix Inc. (Equinix)* 
Exelon Corporation 
FirstEnergy Service Company344 (FirstEnergy)* 
Google LLC* 
Illinois Citizens Utility Board 
Illinois Commerce Commission (ICC)* 
Illinois Municipal Electric Agency 
Institute for Policy Integrity at New York University School of Law (Policy Integrity)345* 
Invenergy Solar Development North America LLC 
Invenergy Thermal Development LLC 
Invenergy Wind Development North America LLC 
J-POWER USA Development Co., Ltd. 
Kentucky Attorney General 
LS Power Development, LLC 
Maryland Office of People’s Counsel 
Maryland Public Service Commission 
Michigan Public Service Commission 
MN8 Energy LLC 
Monitoring Analytics, LLC, acting in its capacity as Independent Market Monitor for 
PJM (Market Monitor)* 
National Grid plc346
New Jersey Board of Public Utilities 
New Jersey Division of Rate Counsel 
Nicholas Max Neal and David Neal, Delaware Standard Offer Service Ratepayers 
344 FirstEnergy Service Company submitted a motion to intervene as agent for its 
franchised public utility and transmission-owning public utility affiliates Ohio Edison 
Company; The Cleveland Electric Illuminating Company; The Toledo Edison Company; 
FirstEnergy Pennsylvania Electric Company; and the FirstEnergy Transmission Owners 
(collectively, Jersey Central Power & Light Company; Monongahela Power Company; 
The Potomac Edison Company; American Transmission Systems, Incorporated; 
Keystone Appalachian Transmission Company; Mid-Atlantic Interstate Transmission, 
LLC; and Trans-Allegheny Interstate Line Company). 
345 Policy Integrity filed comments but did not file a motion to intervene. 
346 National Grid plc submitted a motion to intervene on behalf of its competitive 
energy development corporation National Grid Ventures.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 90 - 
(Movants)* 
North Carolina Electric Membership Corporation (NCEMC)* 
Northeastern Rural Electric Membership Corporation 
Northern Virginia Electric Cooperative, Inc. (NOVEC)* 
NRG Business Marketing LLC347* 
Office of the Illinois Attorney General 
Office of the Ohio Consumers’ Counsel (OCC)* 
Office of the People’s Counsel for the District of Columbia 
Ohio Energy Leadership Council (OELC)* 
Old Dominion Electric Cooperative (ODEC)* 
Organization of PJM States, Inc. (OPSI)* 
Pennsylvania Office of Consumer Advocate (PA OCA)* 
Pennsylvania Public Utility Commission 
Persistence Analytics Group LLC* 
PJM Industrial Customer Coalition (PJMICC)* 
PJM Power Providers Group (P3)* 
PPL Electric Utilities Corporation* 
Public Citizen, Inc 
Public Service Commission of West Virginia (PSCWV)* 
Public Utilities Commission of Ohio’s Office of the Federal Energy Advocate (Ohio 
FEA)* 
Retail Energy Supply Association (RESA)* 
Shell Energy North America (US), L.P. 
Sierra Club348* 
Solar Energy Industries Association (SEIA)* 
Southern Maryland Electric Cooperative, Inc. (SMECO)* 
Talen Energy Corporation (Talen)* 
The Williams Companies, Inc. 
Tract Holding Company I, LLC (Tract)* 
Verrus LLC 
347 NRG Business Marketing LLC submitted a motion to intervene on behalf of its 
public utility affiliates Aspen Gen Funding, LLC; Direct Energy Business, LLC; 
Doswell, LLC; Energy Plus Holdings LLC; Enerwise Global Technologies, LLC dba 
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 Companies, collectively). 
348 Sierra Club filed comments jointly with the National Resource Defense 
Council, who did not file a motion to intervene.

Docket Nos. ER26-3380-000 and EL26-108-000 
- 91 - 
Virginia Municipal Electric Association No. 1 
Virginia State Corporation Commission 
Vistra Corp. (Vistra)* 
Voltus, Inc. 
Wellsboro Electric Company (Citizens’ Electric, collectively with Citizens’ Electric 
Company of Lewisburg, PA)

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
PJM Interconnection, L.L.C. 
Docket No. ER26-3380-000
EL26-108-000
(Issued September 29, 2026) 
SWETT, Chairman, concurring: 
American ratepayers and utilities need urgency, clarity, and discipline—none of 
which PJM appears capable of delivering at this time.  The Reliability Backstop 
Procurement proposal came before us on the last possible statutory day to open a 
procurement window on September 30.  Whether by accident or incompetence, that 
timing left the Commission no meaningful opportunity to issue a deficiency letter, seek 
additional record development, or establish hearing procedures to attempt to rehabilitate 
the mess we received.   
This Commission will not be forced into accepting a deeply flawed, eleventh-hour 
procurement mechanism with billion-dollar implications for consumers.  Today we triage 
the issues and urge PJM to promptly remedy them in a Federal Power Act Section 205 
filing.  We accept certain parts of the proposal that advance urgently needed capacity 
procurement, find that other components require reform, and provide guidance to inform 
expeditious resubmission. 
We are prepared to promptly act on a subsequent proposal that addresses the 
concerns raised in this order and meets the standards of the Federal Power Act.  The 
region’s reliability hangs in the balance.   
For these reasons, I respectfully concur.  
________________________ 
Laura V. Swett 
Chairman

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
PJM Interconnection, L.L.C.
Docket No. ER26-3380-000
(Issued September 29, 2026) 
ROSNER, Commissioner, concurring:  
I concur in today’s order because, at its core, our responsibility to the 67 million 
people in PJM is to keep the lights on.  While the record reflects a wide range of views on 
how best to address the emerging reliability challenges, the downside risk of inaction far 
outweighs the risk of an imperfect solution.  It is not a close call. 
The limited set of guidance we give PJM to revise its proposal will enable PJM to 
assign costs to those responsible (i.e. to the zones with data center growth) for the 
resource adequacy shortfall, consistent with cost causation principles, and it is my hope 
that PJM will act on this guidance swiftly so that needed generation may be procured.   
Many of the issues driving this filing extend beyond PJM’s jurisdiction to solve 
alone.  States and retail authorities must play an active role – particularly in establishing 
large-load retail tariffs, enforcing collateral requirements, and establishing clear rules for 
which customers should be curtailed first when circumstances require it (Hint: homes, 
hospitals, and schools should never be curtailed before data centers).  As the order 
acknowledges,1 these are decisions that sit squarely with states and their regulators, and 
meaningful progress requires their continued leadership. 
In the longer term PJM and its stakeholders must return to market fundamentals.  
Load and supply should have strong incentives to hedge, manage their risks, and procure 
the capacity they rely upon.  Market discipline – not ad hoc backstops – must again 
become the primary safeguard for reliability. 
For these reasons, while acknowledging the imperfections in the filing, I agree that 
taking action today is warranted, and I respectfully concur. 
For these reasons, I respectfully concur. 
________________________ 
David Rosner 
Commissioner 
1 PJM Interconnection, L.L.C., 196 FERC ¶ 61,245, at P 161 (2026).

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
PJM Interconnection, L.L.C.
Docket Nos. ER26-3380-000
(Issued September 29, 2026) 
SEE, Commissioner, concurring: 
PJM needs more generation: Soaring electricity demand from data centers, 
artificial intelligence, domestic manufacturing, and other strategic industries continues to 
challenge a region that faces increasingly tight supply.  Meeting that demand requires 
sufficient generation, including dependable resources that support the system around the 
clock.  PJM must move fast to secure the resources to serve its growing system. 
But how PJM—really, PJM’s ratepayers—pays for those resources matters.  As I 
have said before, customers that drive new costs should bear appropriate responsibility 
for them.  Existing customers should not be left paying costs attributable to new demand.  
That principle is particularly important here where PJM proposes a backstop procurement 
specifically to deal with the capacity shortfall that rapid load growth largely drove. 
PJM needs urgent action and this mechanism, the RBP, can be a critical tool to 
bring additional capacity to the region.  Unfortunately, though, PJM missed the mark on 
an important element of its proposal: it did not adequately ensure that the procurement’s 
costs will be allocated to the customers who drive its need. 
Today’s order is not perfect; the filing it responds to, even less.  But today the 
Commission provides PJM a path forward to solve what its current proposal lacks when it 
comes to fair cost allocation.  PJM should move quickly to take it. 
That work must include a serious focus on load forecasting.  After years of 
relatively flat electricity demand, regulators and grid operators need to adjust to sustained 
and asymmetric growth.  That means better load forecasts, a clearer picture of which 
projects will materialize, and enough generation and infrastructure to serve them.  Better 
information about where, when, and why load is growing also provides a stronger 
foundation for determining who should bear the costs associated with serving that 
growth. 
PJM does not have the luxury of standing still.  The region needs additional 
generation, and I encourage PJM to swiftly return to the Commission with a section 205 
filing we can accept so that the procurement can move forward quickly.  In doing so, 
PJM must better ensure that the customers driving new costs bear appropriate 
responsibility for them and that existing customers are not left paying the bill instead. 
For these reasons, I respectfully concur.

Docket Nos. ER26-3380-000 and EL26-108-000 
                                              - 2 - 
____________________ 
Lindsay S. See 
Commissioner

UNITED STATES OF AMERICA 
FEDERAL ENERGY REGULATORY COMMISSION 
PJM Interconnection, L.L.C. 
Docket Nos. 
ER26-3380-000
EL26-108-000
(Issued September 29, 2026) 
LACERTE, Commissioner, concurring:  
I concur in today’s order but write separately as a reminder of what this order   
is—or should be—about.  Reliability Backstop Procurement is designed to make sure the 
costs of the large load at issue here are appropriately allocated to that load and not to 
other consumers and, in that vein, it is also an attempt to get new assets onto the PJM grid 
in a time of desperate need.   
This is not a problem with an exceedingly easy or even single solution.  While a 
perfect solution may not exist, it does not mean this is an unsolvable problem.  
This moment must be met.  We must do so not only because it is one of the many 
vital issues we are presented with in PJM and other regions of this country, but because it 
is important for Americans to do so.   
The vital nature of the large load integration issue to all Americans is highlighted 
by the very existence of the January 2026 Statement of Principles Regarding PJM1 in 
which the White House National Energy Dominance Council and the governors of all 13 
PJM states joined together to address these large load issues as well as the March 2026, 
White House Ratepayer Protection Pledge which addressed that new large loads will, at a 
minimum, “build, bring, or buy the new generation resources and electricity needed to 
satisfy their new energy demands, paying the full cost of those resources”2 and which 
received broad consensus from utilities, cooperatives, data center developers, and 
governors.3
1 U.S. Department of Energy, Statement of Principles Regarding PJM (Jan. 2026), 
https://www.energy.gov/documents/statement-principles-regarding-pjm. 
2 The White House, Ratepayer Protection Pledge (Mar. 4, 2026), 
https://www.whitehouse.gov/wp-content/uploads/2026/07/Ratepayer-Protection-Pledge-
Signed.pdf.
3 The White House, Ratepayer Protection Pledge (Mar. 2026),

Docket Nos. ER26-3380-000 and EL26-108-000 
                                              - 2 - 
What all of this tells me is that time is of the essence.  While we could orbit these 
issues in additional briefings that would cause additional delay to the reliability backstop 
auction and the hope for relief it provides. 
PJM:  you must take action.  You alone have the ability to resolve the outstanding 
issues in the most time efficient manner by making a section 205 filing under the 
timelines set forth in this order—or sooner—that thoughtfully addresses the infirmities of 
the original filing addressed in this order.  Do not deviate from the principles of ratepayer 
protection in that filing.  
A competent and effective RTO can take this half-baked cake and finish the job.  
Does PJM meet that description?  They’re on the clock.  
For these reasons, I respectfully concur. 
______________________________ 
David LaCerte 
Commissioner 
https://www.whitehouse.gov/ratepayer-protection-pledge.