ER26-3380-000 · 2026-07-31 · PJM Interconnection, L.L.C.

PJM proposes its first reliability backstop procurement

UNITED STATES OF AMERICA  
BEFORE THE  
FEDERAL ENERGY REGULATORY COMMISSION  
  
  
PJM Interconnection, L.L.C. 
) 
 
Docket No. ER26-____-000  
  
  
  
 
 
 
RELIABILITY BACKSTOP PROCUREMENT TO ADDRESS RESOURCE 
ADEQUACY CONCERNS STEMMING FROM LARGE LOADS   
 
 
 
 
 
 
 
 
Craig Glazer 
Vice President–Federal Government Policy 
PJM Interconnection, L.L.C. 
1200 G Street, NW, Suite 600 
Washington, D.C.  20005 
(202) 423-4743  
craig.glazer@pjm.com 
 
Ryan J. Collins 
Vivian W. Chum 
Wright & Talisman, P.C. 
1200 G Street, NW, Suite 600 
Washington, D.C.  20005 
(202) 393-1200  
collins@wrightlaw.com 
chum@wrightlaw.com 
 
Chenchao Lu 
Associate General Counsel 
PJM Interconnection, L.L.C.  
2750 Monroe Blvd. 
Audubon, PA  19403 
(610) 666-2255  
chenchao.lu@pjm.com 
 
 
Attorneys for PJM Interconnection, L.L.C. 
 
 
July 31, 2026

TABLE OF CONTENTS 
 
I. 
THE RBP IS A LEGALLY DURABLE REFORM THAT 
INCORPORATES ONGOING AND FORTHCOMING, 
COMPLEMENTARY STATE ACTIONS TO ADDRESS RBP COST 
ALLOCATION. ...................................................................................................... 6 
A. 
The RBP Is a Just and Reasonable, Interim Step to Address 
Resource Adequacy Challenges .................................................................. 6 
B. 
The RBP Is Consistent with the PJM Governors’ Principles ..................... 9 
C. 
The Success of the RBP Requires State Participation .............................. 10 
D. 
The RBP Adheres to the Legal Precedent on Jurisdiction ........................ 13 
E. 
The RBP Requires Cooperation from Numerous Sectors in Order 
to Meet the Goals of the NEDC/PJM Governors’ Principles 
Document .................................................................................................. 16 
II. 
BACKGROUND .................................................................................................. 19 
A. 
The Critical Issue Fast Path Stakeholder Process ..................................... 19 
B. 
PJM Board Determination ........................................................................ 21 
C. 
PJM’s Large Load Matters........................................................................ 22 
III. 
THE PROPOSED REFORMS TO THE TARIFF AND THE RAA ARE 
JUST AND REASONABLE AND NOT UNDULY DISCRIMINATORY 
OR PREFERENTIAL ........................................................................................... 25 
A. 
Overview of the RBP ................................................................................ 25 
1. 
The RBP is a Reliability Backstop solution tailored to meet 
a specific challenge in the context of a reliability 
requirement shortfall in PJM’s BRAs stemming, in part, 
from the influx of large loads, including data centers .................. 27 
2. 
An ongoing bilateral matching process is a parallel path to 
supporting efforts to bring new capacity to PJM in order to 
meet the PJM Region Reliability Requirement shortfall .............. 30 
B. 
The RTO-Wide RBP Target Is Equal to the Initial RBP Target 
Minus Qualifying RBP Offset UCAP MW and Opt-Out UCAP 
MW (Proposed Tariff, Attachment DD, section 18.1) .............................. 31 
1. 
Initial and Final RBP Targets ....................................................... 31

ii 
2. 
Qualifying RBP Offset UCAP MW (proposed Tariff, 
Attachment DD, section 18.2) ...................................................... 35 
a. 
New load and new demand ............................................... 35 
i. 
Load (demand) must be new (proposed 
Tariff, Attachment DD, section 18.2(c)) ............... 35 
ii. 
Capacity must be new (proposed Tariff, 
Attachment DD, section 18.2(a)) .......................... 35 
iii. 
Matching new load with new capacity 
supports reliability and avoids over-
procurement, under-procurement, and 
double-counting (proposed Tariff, 
Attachment DD, section 18.2(b)) .......................... 37 
b. 
Signed bilateral contracts or Self-Supply generation 
resources (proposed Tariff, Attachment DD, 
sections 18.2(c)(i) and 18.2(c)(ii)) .................................... 39 
c. 
Loads participating as Annual Demand Resources 
or DER Aggregation Resources (proposed Tariff, 
Attachment DD, section 18.2(c)(iii)) ................................ 40 
d. 
Capacity eligible to provide Qualifying RBP Offset 
UCAP MW (proposed Tariff, Attachment DD, 
section 18.2(b)) ................................................................. 40 
e. 
Electric Distributors and other entities provide 
evidentiary support for Qualifying RBP Offset 
UCAP MW (proposed Tariff, Attachment DD, 
section 18.2(c)) ................................................................. 42 
3. 
Opt-out (proposed Tariff, Attachment DD, section 18.1(d)) ........ 44 
C. 
The Procurement Process:  RBP Resources, Offers, RPM Must 
Offer, Clearing, Settlement, and Cost Responsibility (proposed 
Tariff, Attachment DD, sections 18.4, 18.5, and 18.6) ............................. 46 
1. 
The scope of the RBP (proposed Tariff, Attachment DD, 
section 18.4) .................................................................................. 46 
2. 
Overview of seller and buyer obligations ..................................... 49 
3. 
Resources eligible to participate in the RBP must bring new 
capacity to PJM (proposed Tariff, Attachment DD, 
sections 18.5(a) through 18.5(d)) .................................................. 51

iii 
4. 
RBP Sell Offers (proposed Tariff, Attachment DD, 
section 18.5(e)) ............................................................................. 54 
5. 
RBP Sellers Responsible for Actual Network Upgrade 
Costs (proposed Tariff, Attachment DD, section 18.5(e)) ............ 56 
6. 
Must-offer obligation in the RPM for RBP committed 
resources (proposed Tariff, Attachment DD, 
sections 18.6(a) and 18.6(b)) ........................................................ 56 
7. 
RBP UCAP MW shortfalls or failure to materialize 
(proposed Tariff, Attachment DD, sections 18.6(c) through 
18.6(e)) .......................................................................................... 60 
8. 
Clearing structure (proposed Tariff, Attachment DD, 
section 18.5(f)) .............................................................................. 61 
a. 
The MW-weighted average of the levelized 
procurement cost of all selected RBP Sell Offers 
shall not exceed $555/MW-day UCAP............................. 61 
b. 
The proposed maximum willingness is just and 
reasonable ......................................................................... 62 
c. 
The pay-as-bid approach is just and reasonable for 
purposes of the RBP.......................................................... 65 
d. 
No direct market power screens or mitigation .................. 66 
e. 
Stage 1:  gating criteria—ensuring the viability of 
the resource to be developed (proposed Tariff, 
Attachment DD, section 18.5(f)(i)) ................................... 71 
f. 
Stage 2:  selection assessment........................................... 75 
9. 
Contract for difference settlement structure (proposed 
Tariff, Attachment DD, section 18.5(g)) ...................................... 79 
a. 
RBP Settlement Credits and RBP Charges ....................... 82 
b. 
Examples of RBP Resource Settlements .......................... 82 
c. 
Settlement of RBP Resources with MW Shortfalls, 
RBP shortfall charges, RPM Commitment 
Deficiency MW, and RPM Commitment Charges 
(proposed Tariff, Attachment DD, section 18.6(d)) ......... 86

iv 
d. 
Example of RBP Resource Settlements of RBP MW 
Shortfalls, RBP shortfall charges, RPM 
Commitment Deficiency MW, and RPM 
Commitment Charges (proposed Tariff, 
Attachment DD, section 18.6(d)) ...................................... 87 
10. 
Non-payment of RBP Charges and RBP shortfall charges 
(proposed Tariff, Attachment DD, section 18.9) .......................... 89 
11. 
Change in ownership of RBP Resource (proposed Tariff, 
Attachment DD, section 18.6(f)) .................................................. 90 
D. 
Treatment of RBP Commitment in Event of Transmission Owner 
Exit During Term of the Commitment (proposed Tariff, 
Attachment DD, section 18.7) .................................................................. 90 
1. 
Committed RBP Resources in exiting Transmission Owner 
territory (proposed Tariff, Attachment DD, section 18.7(a)) ........ 92 
2. 
Load allocated RBP Charges in exiting Transmission 
Owner territory (proposed Tariff, Attachment DD, 
section 18.7(b)) ............................................................................. 94 
3. 
Rules governing treatment of RBP Resources or load 
allocated RBP Charges in the event of Transmission Owner 
exit are appropriately submitted with this filing ........................... 95 
4. 
The proposed rules governing treatment of RBP Resources 
or load allocated RBP Charges in the event of Transmission 
Owner exit are appropriately set forth in Tariff, 
Attachment DD ............................................................................. 96 
E. 
Allocation of Costs Associated with Resources Procured Through 
the RBP (proposed Tariff, Attachment DD, section 18.3) ........................ 96 
1. 
The proposed cost allocation methodology .................................. 96 
2. 
The proposed method of allocating costs to Electric 
Distributor zones/areas and LSEs within those zones/areas 
is just and reasonable .................................................................. 100 
3. 
The proposed allocation methodology recognizes that 
allocation to retail customers, including data centers, is 
within the states’ and/or RERRAs’ purview ............................... 104

v 
F. 
Credit Requirements of RBP Resources and LSEs Commensurate 
with Risks (Proposed Tariff, Attachment DD, Section 18.8) and 
Management of RBP Defaults (Proposed Tariff, Attachment DD, 
Section 18.9) ........................................................................................... 108 
1. 
Sellers must provide collateral with RBP Sell Offers 
(proposed Tariff, Attachment DD, section 18.8(a)) .................... 112 
2. 
Return of RBP Collateral (proposed Tariff, 
Attachment DD, section 18.8(a)(ii)) ........................................... 113 
3. 
Collateral requirements for RBP Resources traded to a 
different entity than the RBP Seller (proposed Tariff, 
Attachment DD, section 18.8(a)(v)) ........................................... 113 
4. 
Buyers (LSEs) allocated cost responsibility for RBP 
Charges must provide collateral (proposed Tariff, 
Attachment DD, section 18.8(b)) ................................................ 114 
a. 
Determining the inputs to the RBP credit 
requirement ..................................................................... 115 
b. 
Determining an LSE’s RBP credit requirement.............. 118 
c. 
Posting and maintenance of RBP Collateral ................... 120 
d. 
Changes to the RBP credit requirement associated 
with intra-Delivery Year transfers of load and RBP 
UCAP MW cost responsibility ....................................... 121 
5. 
Management of defaults of obligations to pay RBP Charges 
and RBP shortfall charges (proposed Tariff, 
Attachment DD, section 18.9) .................................................... 122 
G. 
Miscellaneous and Conforming Changes ............................................... 123 
1. 
Reliability Backstop Auction (Tariff, Attachment DD, 
section 16.2) ................................................................................ 123 
2. 
Planned Generation Capacity Resource (Tariff, 
Attachment DD, section 5.5A).................................................... 125 
3. 
Notice of intent (Tariff, Attachment DD, section 5.5) ................ 127 
4. 
Minimum Offer Price Rule (proposed Tariff, 
Attachment DD, section 5.14(h-2)) ............................................ 129 
IV. 
CORRESPONDENCE ........................................................................................ 130

vi 
V. 
REQUESTED EFFECTIVE DATE AND CONSENT TO 
MODIFICATION OR SEVERANCE OF ISSUES ............................................ 130 
VI. 
DOCUMENTS ENCLOSED .............................................................................. 133 
VII. 
SERVICE ............................................................................................................ 134 
VIII. 
CONCLUSION ................................................................................................... 135

1200 G Street, N.W., Suite 600 
Washington, D.C.  20005-3898 
Phone: 202.393.1200 
Fax: 202.393.1240 
wrightlaw.com 
July 31, 2026 
 
The Honorable Debbie-Anne A. Reese 
Secretary 
Federal Energy Regulatory Commission 
888 First Street, N.E., Room 1A 
Washington, D.C.  20426 
 
Re: 
PJM Interconnection, L.L.C., Docket No. ER26-__-000 
Reliability Backstop Procurement to Address Resource Adequacy Concerns 
Stemming from New Load Adjustments  
 
Dear Ms. Reese: 
 
PJM Interconnection, L.L.C. (“PJM”), pursuant to section 205 of the Federal Power 
Act (“FPA”), 16 U.S.C. § 824d, hereby submits revisions to the PJM Open Access 
Transmission Tariff (“Tariff”) and the Reliability Assurance Agreement Among Load 
Serving Entities (“RAA”) to establish the Reliability Backstop Procurement (“RBP”)—a 
one-time procurement of new capacity to address resource adequacy challenges in the PJM 
Region1 arising from insufficient commitments of capacity in the 2027/2028 and 
2028/2029 Reliability Pricing Model (“RPM”) Auctions, primarily driven by the 
unprecedented addition of large loads, most notably data centers, in the PJM Region.  The 
RBP framework, as the PJM Board of Managers (“PJM Board”) recognized in a 
January 16, 2026 letter,2 is one part of a multi-pronged, ongoing effort by PJM to respond 
to the challenges stemming from the influx of large loads into the PJM Region.  It is also 
 
1 Capitalized terms not otherwise defined herein have the meaning as defined in the Tariff, Amended and 
Restated Operating Agreement of PJM (“Operating Agreement”), RAA, and Consolidated Transmission 
Owners Agreement (“CTOA”). 
2 David E. Mills, PJM Board Chair, Board Decisional Letter on Critical Issue Fast Path - Large Load 
Additions, PJM Board (Jan. 16, 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-
are/public-disclosures/2026/20260116-pjm-board-letter-re-results-of-the-cifp-process-large-load-
additions.pdf [https://perma.cc/P57T-ZXYJ] (“January 2026 Board Letter”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 2 
 
 
 
just one part of a multi-pronged implementation of the Statement of Principles Regarding 
PJM issued on January 16, 2026, by the National Energy Dominance Council (“NEDC”) 
and the 13 governors of the PJM states.3  The proposed RBP in this filing is consistent with 
the NEDC/PJM Governors’ Principles, which urged PJM to, inter alia,  
• “procure new capacity resources” through a backstop auction, 
• “commencing no later than September 2026,” 
• “[p]rovide 15-year price certainty for new capacity resources,” and  
• “allocate the cost of any new capacity procured through the aforementioned 
[RBP] to [Load Serving Entities (“LSE”)] with new data centers that have 
not self-procured new capacity or agreed to be curtailable.”4     
The RBP proposal is a just and reasonable means to address the influx of large loads 
while maintaining resource adequacy, reliability, and affordability in a manner that respects 
the divide between state and federal authorities and avoids disrupting existing commercial 
arrangements.  Given the pressing resource adequacy concerns arising from the pace and 
volume of large load additions in the PJM Region, PJM requests that the Federal Energy 
Regulatory Commission (“Commission” or “FERC”) issue an order on this filing, and 
make this proposal effective, by no later than September 29, 2026, which is 60 days after 
 
3 Statement of Principles Regarding PJM, National Energy Dominance Council, 1 (Jan. 16, 2026), 
https://www.energy.gov/documents/statement-principles-regarding-pjm 
[https://perma.cc/35HJ-W56E] 
(“NEDC/PJM Governors’ Principles”).  The PJM states include the 13 states of Delaware, Illinois, Indiana, 
Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, and 
West Virginia, and the District of Columbia. 
4 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 3 
 
 
 
the date of this filing.  Commission action by such date, plus the requested effective date, 
will allow PJM to commence the RBP immediately thereafter.5       
Each element of this proposal is just and reasonable.  Nevertheless, in the event the 
Commission deems necessary, and to help facilitate the Commission’s acceptance of this 
filing without delay so that the RBP can commence as soon as possible, PJM provides 
notice that it consents to the Commission’s exercise of authority to modify and/or sever 
any element of the proposed Tariff and RAA language to the extent necessary and 
permitted under section 205 of the FPA and NRG Power Marketing, LLC v. FERC,6 where 
such modification and/or severance is consistent with PJM’s overarching objectives in this 
filing.  PJM cautions, however, to the extent that modification and/or severance of specific 
provisions of the proposal gives rise to complications, it may delay the opening of the RBP 
procurement window, and such delay could cause downstream impacts such as the need to 
delay the Base Residual Auction (“BRA”) for the 2029/2030 Delivery Year that is currently 
scheduled for December.   
As further discussed infra Part V, to the extent the Commission exercises such 
authority to modify the proposed Tariff or RAA language herein pursuant to the FPA and 
NRG Power Marketing, PJM respectfully requests that the Commission expressly prescribe 
 
5 The RBP procurement window will open if and when a Commission order accepts PJM’s proposed RBP 
framework.  To the extent the RBP framework is accepted by September 29, 2026, and absent significant 
revisions or developments, PJM intends to open the procurement window on September 30, 2026.   
6 NRG Power Mktg., LLC v. FERC, 862 F.3d 108 (D.C. Cir. 2017).  As the Commission has repeatedly stated, 
“[t]he United States Court of Appeals for the District of Columbia Circuit has held that, in certain 
circumstances, the Commission has ‘authority to propose modifications to a utility’s [FPA section 205] 
proposal if the utility consents to the modifications.’”  N.Y. Indep. Sys. Operator, Inc., 188 FERC ¶ 61,051, 
at P 22 n.36 (2024) (alteration in original) (citing NRG Power Mktg., 862 F.3d at 114-15); see Midcontinent 
Indep. Sys. Operator, Inc., 180 FERC ¶ 61,141, at P 26 n.29 (2022) (same), order on reh’g, 182 FERC 
¶ 61,096 (2023); ISO New Eng. Inc., 175 FERC ¶ 61,172, at P 16 n.20 (2021) (same).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 4 
 
 
 
the revised language to provide the “necessary predictability” for PJM to implement such 
change(s) even before issuance of an order on compliance.7  PJM’s submittal of any 
compliance filing implementing such modifications would further constitute PJM’s 
consent and acceptance of the Commission’s modifications.  PJM has the authority to 
consent to modifications to PJM’s proposal by the Commission, pursuant to the FPA and 
NRG Power Marketing.  In contrast to the underlying facts in NRG Power Marketing, the 
proposal submitted in this filing was authorized by the PJM Board and was not the result 
of a stakeholder-endorsed proposal.8 
Significantly, while this FPA section 205 filing is focused on the RBP framework, 
PJM intends to quickly follow this filing with another FPA section 205 filing to propose 
an interim resource adequacy service (“IRAS”).  That forthcoming 205 filing will explain 
how load in an Electric Distributor’s zone/area that has brought its own new capacity or 
has had capacity allocated to it through the RBP framework will be at lower risk of load 
reduction through the IRAS structure.  Furthermore, IRAS will support ongoing state 
 
7 PJM Interconnection, L.L.C., 175 FERC ¶ 61,137, at P 110 (2021) (first quoting Aera Energy LLC v. FERC, 
789 F.3d 184, 190-92 (D.C. Cir. 2015) “affirming the Commission, finding ‘FERC’s conditional acceptance 
. . . simply required Kern River to substitute one number for another when allocating costs to the rolled-in 
shippers. . . . Because this mechanical change gave Kern River no discretion to adjust its rate models, FERC 
provided sufficient notice to ratepayers’”, and then quoting Elec. Dist. No. 1 v. FERC, 774 F.2d 490, 493 
(D.C. Cir. 1985) “vacating when the ‘effective date of an order set[] forth no more than the basic principles 
pursuant to which the new rates are to be calculated’” (alteration in original)).  As the Commission elaborated 
further in PJM Interconnection, 175 FERC ¶ 61,137 at P 110, mere “direction” without “sufficient detail on 
each element [of the replacement rate] that [customers/market participants] could determine when their 
transactions would be subject to [the new rule],” would mean that implementation of the compliance directive 
prior Commission approval would violate the filed rate doctrine.  Id. (quoting Elec. Dist. No. 1, 774 F.2d at 
493 “[P]urchasers of electricity cannot plan their activities unless they know the cost of what they are 
receiving, ‘providing the necessary predictability is the whole purpose of the well-established filed rate 
doctrine.’” (citing Ark. La. Gas Co. v. Hall, 453 U.S. 571, 577 (1981))). 
8 NRG Power Marketing, 862 F.3d at 112 (noting that PJM developed proposed revisions filed with the 
Commission through its stakeholder process and that the proposed revisions “received overwhelming support 
from PJM’s stakeholders”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 5 
 
 
 
efforts to create operational procedures to reduce large loads that have not brought their 
own new capacity ahead of residential and traditional industrial customers.  The interim 
resource adequacy filing will provide further information to the Commission and 
stakeholders as to the multipronged PJM initiatives to address large load additions.9  
Although the forthcoming IRAS proposal may refer to the RBP, the two filings are 
independent of each other.  In short, the RBP can and should proceed as requested in this 
filing even if the Commission wishes to further examine portions of an IRAS filing that 
may be pending before the Commission at the time.   
Moreover, the RBP is among the stop-gap solutions being proposed by PJM while 
PJM continues to make progress on a broader, holistic review of its capacity market, the 
RPM, to identify durable, more permanent solutions to concerns stemming from large load 
additions.10   
On May 9, 2026, PJM issued a white paper, Powering Reliability Through Market 
Design: Addressing Rising Demand and Constrained Supply, and Stimulating Investment 
to Support Durable Reliability, which inter alia, posed foundational questions facing 
PJM’s capacity market today and proffered three distinct, albeit not mutually exclusive, 
 
9 PJM anticipates that the forthcoming section 205 filing proposing an IRAS will also address the recent 
announcement by the PJM Board that “[i]ncremental new Large Loads relative to the forecast utilized for the 
2028/2029 BRA will be excluded from the forecast used in future RPM auctions for the 2029/2030 Delivery 
Year and beyond unless and until there are new supply resources offered into an RPM auction in sufficient 
quantity to cover the new Large Load.”  CIFP Framework for Service During Periods of Insufficient 
Resource Adequacy – PJM Proposal, PJM Interconnection, L.L.C., 5 (July 27, 2026), https://www.pjm.com/-
/media/DotCom/about-pjm/who-we-are/public-disclosures/2026/20260727-cifp-framework-for-service-
during-periods-of-insufficient-resource-adequacy-executive-summary.pdf [https://perma.cc/46RD-UQBC]. 
10 See Powering Reliability Through Market Design: Addressing Rising Demand and Constrained Supply, 
and Stimulating Investment to Support Durable Reliability (May 9, 2026), https://www.pjm.com/-
/media/DotCom/library/reports-notices/special-reports/2026/20260506-powering-reliability-through-
market-design.pdf [https://perma.cc/3W8Z-M4TQ] (“Powering Reliability Through Markets White Paper”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 6 
 
 
 
paths forward.11  These foundational questions and proposed paths forward are a starting 
point towards more permanent solutions to PJM’s resource adequacy concerns.12  This 
ongoing holistic review is in line with the NEDC/PJM Governors’ Principles, which urged 
PJM to “embark on a stakeholder process to reform the capacity market to ensure long-
term viability and prevent consumers from bearing excessive ongoing costs,” with an 
ultimate goal of returning PJM to market fundamentals.13  
I. 
THE RBP IS A LEGALLY DURABLE REFORM THAT INCORPORATES 
ONGOING 
AND 
FORTHCOMING, 
COMPLEMENTARY 
STATE 
ACTIONS TO ADDRESS RBP COST ALLOCATION 
A. 
The RBP Is a Just and Reasonable, Interim Step to Address Resource 
Adequacy Challenges.  
PJM hosts the largest concentration of data center load in the world.14  “PJM’s load 
forecast predicts peak load growth of 32 gigawatts [(“GW”)] from 2024 to 2030, 30 GW 
of which is projected to be from data centers.”15  Year-over-year, the shortfall of capacity 
 
11 Id. 
12 PJM Interconnection, L.L.C., PJM to Lead Market Reform Effort to Support Generation Investment and 
Reliability, PJM Inside Lines (May 6, 2026), https://insidelines.pjm.com/pjm-to-lead-market-reform-effort-
to-support-generation-investment-and-reliability/ [https://perma.cc/J2KW-LRW2]. 
13 NEDC/PJM Governors’ Principles at 1; see also PJM Interconnection, L.L.C., CIFP Reliability Backstop 
Procurement – PJM Proposal, 1 (June 11, 2026), https://www.pjm.com/-/media/DotCom/committees-
groups/cifp-rbp/2026/20260611/20260611-item-04a---pjm-reliability-backstop-proposal---post-meeting-
materials.pdf [https://perma.cc/X7T7-5RPB] (providing background on stakeholder engagement). 
14 See, e.g., Laila Kearney, Biggest US power grid operator moving forward with plan to manage data 
centers, Reuters (Nov. 20, 2025), https://www.reuters.com/business/energy/biggest-us-power-grid-operator-
moving-forward-with-plan-manage-data-centers-2025-11-19/ [https://perma.cc/7M34-52V4]. 
15 PJM Interconnection, L.L.C., 195 FERC ¶ 61,211, at P 8 & n.24 (2026) (“June 2026 Order to Show Cause”) 
(citing Letter from David E. Mills, PJM Board Chair, PJM Interconnection, L.L.C. to PJM Stakeholders 
(Aug. 
8, 
2025), 
https://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-
disclosures/2025/20250808-pjm-board-letter-re-implementation-of-critical-issue-fast-path-process-for-
large-load-additions.pdf [https://perma.cc/F9KV-B7HK] (“August 2025 Board Letter”)).  Since the issuance 
of the August 2025 Board Letter, PJM has published its 2026 Long-Term Load Forecast Report, which 
anticipates lower peak demand in the near term due to forecasting improvements, revising the peak load 
forecast for 2030 downward by 875 megawatts (“MW”), but confirms significant growth in the next 20 years.  
PJM Interconnection, L.L.C., PJM’s Updated 20-Year Forecast Continues to See Significant Long-Term

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 7 
 
 
 
supply needed to meet demand (plus a reasonable reserve margin) has grown despite a net 
increase of 1,294.4 MW Installed Capacity (“ICAP”) of supply between the 2027/2028 and 
2028/2029 BRA.16  In other words, the addition of new supply has not kept pace with rapid 
large load demand growth, thus giving rise to the significant tightening of the capacity 
market in recent years and the subsequent resource adequacy shortfalls.  To mitigate the 
potential reliability risks associated with resource adequacy shortfalls, PJM is proposing 
this RBP as a one-time, supplementary mechanism to procure additional supply to meet 
the resource adequacy needs of the PJM Region. 
The 2028/2029 BRA Report, dated July 14, 2026, indicates PJM’s BRA cleared 
short of the PJM Region Reliability Requirement17 for a second consecutive year.18  
Specifically, PJM’s BRA for the 2028/2029 Delivery Year, which ran from June 30, 2026, 
to July 7, 2026, cleared 6,831.3 MW (in Unforced Capacity (“UCAP”)) short of PJM’s 
Regional Transmission Organization (“RTO”)-wide reliability requirement at the market 
price cap of $325/MW-day.19    
 
Load Growth, PJM Inside Lines (Jan. 14, 2026), https://insidelines.pjm.com/pjms-updated-20-year-forecast-
continues-to-see-significant-long-term-load-growth/ [https://perma.cc/W3UY-F9HE]. 
16 2028/2029 Base Residual Auction Report, PJM Interconnection, L.L.C., 8 (July 14, 2026), 
https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-auction-info/2028-2029/2028-2029-bra-
results-report.pdf [https://perma.cc/A53K-TXXY] (“2028/2029 BRA Report”). 
17 Tariff, Part I, section 1, Definitions – O, P, Q—PJM Region Reliability Requirement (“‘PJM Region 
Reliability Requirement’ shall mean, for purposes of the Base Residual Auction, the Forecast Pool 
Requirement multiplied by the Preliminary PJM Region Peak Load Forecast, less the sum of all 
Preliminary Unforced Capacity Obligations of [Fixed Resource Requirement (“FRR”)] Entities in the PJM 
Region; and, for purposes of the Incremental Auctions, the Forecast Pool Requirement multiplied by the 
updated PJM Region Peak Load Forecast, less the sum of all updated Unforced Capacity Obligations of FRR 
Entities in the PJM Region.”). 
18 2028/2029 BRA Report at 3. 
19 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 8 
 
 
 
Last year, PJM’s BRA for the 2027/2028 Delivery Year, which ran from 
December 4, 2025, through December, 10, 2025, likewise cleared 6,623 MW short of the 
PJM Region Reliability Requirement, at the market  price cap of $333.44/MW-day 
(UCAP).20  As both the Commission and the Department of Energy have recently 
highlighted, the pace of “growth [in electricity demand] is now higher than at any point in 
the past two decades, driven in part by increasing quantities of large commercial and 
industrial load, most notably data centers, connecting rapidly to the transmission system.”21   
As proposed, the RBP will commence upon Commission acceptance of this filing 
with the goal of obtaining commitments of new RBP UCAP MW from eligible resources, 
called RBP Resources, for a fixed term of up to 15 years, starting with the 2028/2029 
Delivery Year and ending with the 2042/2043 Delivery Year.  The commitment term for 
RBP Resources that are scheduled to commence service after the 2028/2029 Delivery Year 
will be shortened by a commensurate number of years, as no commitment will extend 
beyond the 2042/2043 Delivery Year.  The RBP will aim to procure capacity equal to the 
Final RBP Target, which, as discussed below, will initially be based on the observed MW 
UCAP shortfall in the BRA for PJM’s 2028/2029 Delivery Year, i.e., the Initial RBP 
Target.  The Initial RBP Target will be adjusted to reflect qualifying new capacity serving 
 
20 PJM Auction Procures 134,479 MW of Generation Resources, PJM Interconnection, L.L.C., 1 (Dec. 17, 
2025), https://www.pjm.com/-/media/DotCom/about-pjm/newsroom/2025-releases/20251217-pjm-auction-
procures-134479-mw-of-generation-resources.pdf [https://perma.cc/A89W-W99B]. 
21 June 2026 Order to Show Cause, 195 FERC ¶ 61,211 at P 6 & n.18 (citing Interconnection of Large Loads 
to the Interstate Transmission System, Secretary of Energy’s Direction that the Federal Energy Regulatory 
Commission Initiate Rulemaking Procedures and Proposal Regarding the Interconnection of Large Loads 
Pursuant to the Secretary’s Authority Under Section 403 of the Department of Energy Organization Act, 
Docket No. RM26-4-000, Advance Notice of Proposed Rulemaking at 2 (Oct. 23, 2025) (“DOE ANOPR”) 
(citing 2024 Long- Term Reliability Assessment, Northern American Electric Reliability Corporation, 8 (Dec. 
2024, 
corrected 
July 
11, 
2025), 
https://www.nerc.com/globalassets/our-work/assessments/2024-
ltra_corrected_july_2025.pdf [https://perma.cc/Z4D4-AMQT])).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 9 
 
 
 
new load and certain qualifying Electric Distributors that elect and meet requirements to 
opt-out of the RBP.22   
B. 
The RBP Is Consistent with the PJM Governors’ Principles. 
Key aspects of the RBP—including the timing of the RBP, the fixed 15-year term 
for newly procured RBP Resources, the Final RBP Target, and cost allocation—are 
consistent with and informed by the NEDC/PJM Governors’ Principles.  Specifically, the 
NEDC and the 13 governors of the PJM states expressly urged PJM to:  
• “expeditiously” file revisions to PJM’s Tariff;   
• “[p]rovide 15-year price certainty for new capacity resources”;  
• hold an “[a]uction to procure new capacity resources commencing no later 
than September 2026”;  
• “[a]llocate [c]osts to [d]ata [c]enters”;   
• “allocate the cost of any new capacity procured through the 
aforementioned . . . [a]uction to load serving entities (LSEs) with new data 
centers that have not self-procured new capacity or agreed to be 
curtailable”; and   
• allocate any remaining costs “to LSEs based on their remaining net short 
positions.”23      
The RBP, as proposed herein, reflects the due consideration given to the NEDC/PJM 
Governors’ Principles.  At the same time, the RBP reflects the input of stakeholders, as 
well as PJM’s judgment and analyses in shaping the specific means to implement the 
Principles document.  The resulting proposal is a just and reasonable and not unduly 
discriminatory or preferential set of reforms aimed at securing new capacity resources to 
address the recently observed PJM Region Reliability Requirement shortfall.   
 
22 Since this Spring, PJM has been concurrently facilitating a bilateral matching process to encourage 
voluntary, bilateral agreements between supply and demand for new capacity.   
23 NEDC/PJM Governors’ Principles at 1.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 10 
 
 
 
C. 
The Success of the RBP Requires State Participation.  
The PJM states24 will each play a central role in protecting their respective 
residential customers from cost shifts.  Indeed, as a product of cooperative federalism, the 
RBP specifically contemplates a framework in which both PJM and the PJM states have 
distinct roles, within the boundaries of their respective jurisdictional authorities.   
The proposed RBP framework is the result of a carefully considered effort to 
respect the line between federal and state jurisdiction while simultaneously embracing 
PJM’s significant role in (1) meeting the region’s resource adequacy needs and 
(2) supporting the reliable and orderly interconnection of large loads in the region.  As “a 
creature of statute,” the Commission “has jurisdiction over only those matters that 
Congress has given it authority to regulate.  That authority includes jurisdiction over the 
wholesale sale and transmission of electricity in interstate commerce, including all 
facilities used for such sale and transmission.”25  PJM cannot “confer jurisdiction where 
the Commission otherwise lacks jurisdiction.”26   
In a letter to PJM on June 30, 2026, Chair of the Virginia State Corporation 
Commission (“VA SCC”) Judge Kelsey Bagot and the President and CEO of the Data 
Center Coalition (“DCC”) Josh Levi recently highlighted that the goals of the PJM states’ 
public utility commissions “to ensure reliable electric service, just and reasonable retail 
rates, and to protect residential and traditional industrial customers from undue cost shifts,” 
 
24 The District of Columbia did not sign the NEDC/PJM Governors’ Principles. 
25 June 2026 Order to Show Cause, 195 FERC ¶ 61,211 at P 46 (citing Atl. City Elec. Co. v. FERC, 295 F.3d 
1, 8 (D.C. Cir. 2002); 16 U.S.C. § 824(b)(1)). 
26 PJM Interconnection, L.L.C., 114 FERC ¶ 61,191, at P 17 (2006).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 11 
 
 
 
need not be incompatible with the goal of “serving emerging large loads.”27  However, as 
the VA SCC and DCC Letter recognizes, serving emerging large loads while meeting the 
mandates of the PJM state utility commissions will “require proactive collaboration among 
states, industry, and PJM to develop standardized regulatory tools and model retail tariff 
structures that individual state commissions may consider as they address the integration 
of new large electric loads.”28  
Indeed, the RBP framework relies on each of the PJM states to refine, for purposes 
of cost allocation, which retail loads—including which “large loads,” as each state defines 
such loads—should be allocated the costs of resources procured through the RBP.  The 
RBP framework furthermore affords the PJM states with the flexibility needed to carry out 
the recent pledge of the PJM states’ 13 governors to “[u]se their [a]uthorities to [a]llocate 
[c]osts to [d]ata [c]enters and [p]rotect [r]esidential [c]ustomers.”29   
Pursuant to the cooperative federalism framework that underpins the FPA, federal 
and state counterparts are already working to address challenges in the PJM Region 
stemming from the rapid addition of large loads, including data centers.  As the 
Commission recently noted with approval, “efforts taken by states to reform retail tariffs 
to address the potential for retail cost shifting as large loads come online,” have been 
“encourag[ing].”30   
 
27 Letter of Chair of Virginia State Corporation Commission, Kelsey Bagot and President and CEO of Data 
Center Coalition, Josh Levi to Ms. Paula Conboy, Chair of PJM Board of Managers, and Mr. David Mills, 
President and CEO of PJM Interconnection, L.L.C., at 1 (June 30, 2026), https://www.pjm.com/-
/media/DotCom/committees-groups/cifp-rbp/2026/20260630/20260630-written-comments---va-scc-and-
data-center-coalition.pdf [https://perma.cc/S7C6-C86H ] (“VA SCC and DCC Letter”). 
28 Id. 
29 NEDC/PJM Governors’ Principles at 2. 
30 June 2026 Order to Show Cause, 195 FERC ¶ 61,211 at P 69.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 12 
 
 
 
First, in the NEDC/PJM Governors’ Principles, the PJM states’ 13 governors 
pledged 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 . . . [a]uctions to new data center 
loads that have not otherwise procured capacity or agreed to 
be curtailable.31   
Second, the VA SCC and DCC have agreed to work collaboratively to “develop 
model state tariff provisions addressing the retail allocation of costs associated with PJM’s 
Reliability Backstop Procurement” by “no later than January 1, 2028.”32  According to the 
VA SCC and DCC, the objective of this collaborative effort is to “develop transparent retail 
mechanisms that appropriately align reliability backstop costs to the large load customers 
whose demand contributes to the need for those procurements, while protecting existing 
residential and traditional industrial customers from inappropriate cost shifts.”33  
The VA SCC and DCC have also pledged to convene a joint working group with 
other states to develop model retail emergency load reduction programs that will establish 
the retail mechanisms needed to authorize curtailment of designated large commercial and 
industrial customers before the implementation of broader manual load shed, and to 
develop retail interruptible service tariffs by “no later than February 1, 2027.”34 
 
31 NEDC/PJM Governors’ Principles at 2. 
32 VA SCC and DCC Letter at 3. 
33 Id. 
34 Id. at 2.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 13 
 
 
 
D. 
The RBP Adheres to the Legal Precedent on Jurisdiction.  
The jurisdictional divide embedded in the RBP proposal adheres to the relevant 
precedent on jurisdiction.  First, on October 23, 2025, the Department of Energy issued an 
Advanced Notice of Proposed Rulemaking (“ANOPR”), which called on the Commission 
to consider “potential reforms to ensure the timely and orderly interconnection of large 
loads to the transmission system.”35  The Commission’s subsequent Order Regarding Intent 
to Act on the ANOPR (“Order on DOE ANOPR”),36 found, inter alia, that large loads 
present an urgent need for reforms to ensure their timely, orderly, and non-discriminatory 
connection to the transmission system.37  Nevertheless, “the addition of and service to large 
loads” and the associated rates, terms, and conditions “implicate both federal and state 
interests.”38  Accordingly, the Commission observed, “resolution of issues related to large 
load additions will require the involvement of both federal and state actors, including the 
Commission, state public utility commissions, and other state and local entities.”39  Indeed, 
 
35 DOE ANOPR at P 1 (citations omitted). 
36 Interconnection of Large Loads to the Interstate Transmission System, 195 FERC ¶ 61,045 (2026). 
37 Id. at P 2. 
38 June 2026 Order to Show Cause, 195 FERC ¶ 61,211 at P 44; see also PJM Interconnection, L.L.C., 193 
FERC ¶ 61,217, at P 165 (2025) (“December 2025 Show Cause Order”) (Issues pertaining to large loads 
“implicate both federal and state interests, and their resolution will require the involvement of both federal 
and state actors, including the Commission, state public utility commissions, and other state and local 
entities.”); PJM Interconnection, L.L.C., 195 FERC ¶ 61,197, concur op. (Commissioner Rosner) at P 2 
(2026) (“[P]ublic utility commissioners, governors’ offices, and state legislatures are all necessary partners 
in ensuring that energy infrastructure is built at the pace needed to stay ahead of demand and keep energy 
affordable and reliable for PJM customers.”). 
39 June 2026 Order to Show Cause, 195 FERC ¶ 61,211 at P 44.  See also id. at P 48 (Notably, the Commission 
has expressly “recognize[d] that states will continue to regulate:  (1) the specific terms of retail sales to large 
load; (2) which entities may make retail sales within their borders; . . . and (3) any siting decisions and 
construction associated with the large load project.” (citations omitted)); December 2025 Show Cause Order, 
193 FERC ¶ 61,217 at P 165 (issues pertaining to large loads “implicate both federal and state interests, and 
their resolution will require the involvement of both federal and state actors, including the Commission, state 
public utility commissions, and other state and local entities.”); PJM Interconnection, 195 FERC ¶ 61,197, 
concur op. (Commissioner Rosner) at P 1 (“[P]ublic utility commissioners, governors’ offices, and state

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 14 
 
 
 
as the Commission’s Order on DOE ANOPR points out, in the last several years, the 
Commission has accepted proposed tariffs and agreements “related to large loads 
connecting to the transmission system . . . while rejecting those that exceed the 
Commission’s jurisdiction or failed to reasonably allocate costs.”40   
Second, the proposed RBP framework also recognizes that the PJM states and other 
PJM stakeholders must also act to address cost allocation concerns stemming from new 
large loads.41  The division of authority and responsibility between PJM and the PJM states 
is firmly rooted in the Supreme Court’s holding in FERC v. EPSA.42  There, the Supreme 
Court held that the Commission’s regulation of demand response “addresses—and 
addresses only—transactions occurring on the wholesale market” and takes aim at 
“enhanc[ing] the wholesale, not retail, electricity market.”43  The Supreme Court 
accordingly held that the Commission’s rules for demand response withstood EPSA’s 
jurisdictional challenge by respecting the division of federal/state authority set forth in the 
FPA.44  Even though the FPA’s drafters could not have anticipated demand response, its 
regulation was nevertheless consistent with the division of jurisdictional authority 
 
legislatures are all necessary partners in ensuring that energy infrastructure is built at the pace needed to stay 
ahead of demand and keep energy affordable and reliable for PJM customers.”). 
40 Order on DOE ANOPR, 195 FERC ¶ 61,045 at P 2 (citation omitted). 
41 PJM recognizes that the Commission’s June 18, 2026 Order to Show Cause in Docket No. EL26-67-000 
found that PJM’s Tariff may be unjust and unreasonable and unduly discriminatory or preferential because 
it does not include a definition of large load for the PJM Region.  June 2026 Order to Show Cause, 195 FERC 
¶ 61,211 at P 58.  PJM intends to propose a definition of Large Load for the PJM Region in a subsequent 
filing.  However, for purposes of the RBP framework, “large load,” as used herein, refers broadly to the 
recent influx of load, including data centers or, in the context of retail cost allocation, refers to the term to 
the extent defined by each of the PJM states.   
42 FERC v. Elec. Power Supply Ass’n, 577 U.S. 260 (2016) (“EPSA”). 
43 Id. at 282, 287. 
44 Id. at 288-91.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 15 
 
 
 
contemplated by the FPA—in which the Commission, and thereby RTOs/Independent 
System Organizations (“ISO”), retain authority over wholesale transactions, while states 
regulate retail transactions.45   
The reforms in this filing address issues that the FPA’s drafters would have 
certainly considered science fiction—the impact of large loads, including data centers, 
driven primarily by exponential technological advancements in artificial intelligence.  
Nevertheless, PJM has taken care to divide responsibilities between PJM and the states in 
a manner consistent with the FPA’s basic division of authority.  PJM’s resulting proposal 
is therefore legally durable.   
Third, while the Commission recently noted that it, too, shares concerns “about the 
impact that large load additions can have on retail ratepayers, particularly the concern that 
other retail ratepayers may be forced to subsidize Network Upgrades needed to add large 
loads to the transmission system,” the Commission also recognized that the scope of its 
regulatory authority is nevertheless limited.46  “Specifically,” it is the PJM states that “have 
authority over how the wholesale costs of providing electricity, including transmission of 
such electricity, to those retail customers are recovered through retail rates.”47   
Likewise, an order to show cause issued by the Commission on February 20, 2025, 
on aspects of the co-location of large loads held that:  
states retain exclusive jurisdiction over the terms of retail 
sales . . . including . . . how the costs of the wholesale sale 
and transmission of electricity assigned to a wholesale 
 
45 See Matthew R. Christiansen, FERC v. EPSA: Functionalism and the Electricity Industry of the Future, 68 
Stan. L. Rev. (Apr. 2016), https://www.stanfordlawreview.org/online/ferc-v-epsa/ [https://perma.cc/6QRP-
KXET] (citing EPSA, 577 U.S. at 265-68). 
46 June 2026 Order to Show Cause, 195 FERC ¶ 61,211 at P 69. 
47 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 16 
 
 
 
customer are allocated among that wholesale customer’s 
retail customers.  Thus, while a State may not conclude in 
setting retail rates that the FERC-approved wholesale rates 
are unreasonable, it is within a state’s exclusive jurisdiction 
to determine how those FERC-approved rates are collected 
among the relevant retail customers.48   
At bottom, “exclusive jurisdiction”49 rests with the states to ensure that the 
appropriate retail customers, i.e., new large loads, including data centers—and not 
residential customers or small industrial customers—are suballocated costs associated with 
the wholesale costs of RBP Resources procured through the RBP.  As part of the RBP 
framework, PJM proposes to allocate the wholesale costs of RBP Resources to wholesale 
customers based on longstanding cost allocation principles (see infra Part III.E).  But PJM 
can only do so much; thus, the PJM states must subsequently allocate the costs allocated 
by PJM by dividing them further among the appropriate retail customers, including data 
centers and other large loads, in accordance with state policies, laws, and regulatory 
authority over retail rates and customers. 
E. 
The RBP Requires Cooperation from Numerous Sectors in Order to Meet 
the Goals of the NEDC/PJM Governors’ Principles Document.  
For the PJM Region to address the RBP Target—and more broadly, to meet the 
moment—suppliers of capacity must contribute by voluntarily supplying Qualifying RBP 
Offset UCAP MW or submitting RBP Sell Offers in the RBP.  The success of the RBP also 
requires the participation and cooperation of LSEs serving large loads.  PJM recognizes 
that large loads, including data center developers, have committed to “build, bring, or buy 
 
48 PJM Interconnection, L.L.C., 190 FERC ¶ 61,115 at P 68, order directing compliance, December 2025 
Show Cause Order, 193 FERC ¶ 61,217 (2025). 
49 Id. (emphasis added).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 17 
 
 
 
the new generation resources and electricity needed to satisfy their new energy demands” 
and to pay “the full cost of those resources.”50   
Because the success of the procurement effort turns on them, at least in part, PJM 
highlights several of the representations, pledges, and commitments from various entities 
that have been made in the past year.  First, in its June 2026 Order to Show Cause, the 
Commission highlighted the “voluntary efforts by transmission owners to protect retail 
ratepayers through cost recovery agreements with large loads” and “the execution of the 
President’s Ratepayer Protection Pledge, through which data center developers have 
committed to shield retail ratepayers from increased electricity prices.”51   
Second, in the President’s Ratepayer Protection Pledge, Amazon, Google, Meta, 
Microsoft, OpenAI, Oracle, and xAI pledged, on March 4, 2026, to: 
• build, bring, or buy the new generation resources and electricity needed 
to satisfy their new energy demands, paying the full cost of those 
resources whether by building, or buying from, new or otherwise 
additive power plants.  Where possible, these companies will also add 
more capacity that serves the broader public by increasing supply;52 and 
• negotiate new, separate rate structures with their utilities and relevant 
State governments wherever they build data centers.  Importantly, they 
will pay these rates for the power and related infrastructure that are 
brought online to service their data centers, whether they use the 
electricity or not.53 
 
50 
Ratepayer 
Protection 
Pledge, 
The 
White 
House 
(Mar. 
4, 
2026), 
https://www.whitehouse.gov/releases/2026/03/ 
ratepayer-protection-pledge/ [https://perma.cc/N8PH-K82T] (“Ratepayer Protection Pledge”). 
51 June 2026 Order to Show Cause, 195 FERC ¶ 61,211 at P 69. 
52 Ratepayer Protection Pledge; see also Fact Sheet: President Donald J. Trump Advances Energy 
Affordability 
with 
the 
Ratepayer 
Protection 
Pledge, 
The 
White 
House 
(Mar. 
4, 
2026), 
https://www.whitehouse.gov/fact-sheets/2026/03/fact-sheet-president-donald-j-trump-advances-energy-
affordability-with-the-ratepayer-protection-pledge/ [https://perma.cc/N366-NGF4] (listing the companies 
who joined the Ratepayer Protection Pledge).  
53 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 18 
 
 
 
Subsequently, on July 23, 2026, the signatories to the Ratepayer Protection Pledge 
expanded to include more than 200 utilities, data center developers, and cooperatives, and 
state governors, including the governors of PJM states Tennessee, West Virginia, Ohio, 
and Indiana.54 
Third, there is robust appetite for new capacity to serve new large loads, as shown 
by the representations made by LSEs, large loads, Transmission Owners, and suppliers of 
RBP UCAP MW in response to a Request for Information (“RFI”) issued in April of this 
year.55  The RFI revealed substantial large load interest from 21 entities representing 47 
potential projects in the PJM Region averaging 850 MW each, with a median size of 300 
MW.56  The supply-side response to the RFI was also significant, with 397 potential 
projects by 87 entities and approximately 136 gigawatt in total potential capacity.57  Of the 
supply-side projects, 72% indicated a readiness to engage with their large load counterparts 
immediately, while 91% of the large load projects represented a readiness to engage now.58 
 
54 See President Trump’s Ratepayer Protection Pledge Secures American AI Dominance, Protects 
Consumers, The White House (July 23, 2026), https://www.whitehouse.gov/releases/2026/07/president-
trumps-ratepayer-protection-pledge-secures-american-ai-dominance-protects-consumers/ 
[https://perma.cc/9VDB-B4EH] (“Ratepayer Protection Pledge Announcement”). 
55 PJM Reliability Backstop RFI Summary, Charles River Associates (May 27, 2026), https://www.pjm.com/-
/media/DotCom/committees-groups/cifp-rbp/2026/20260527/20260527-informational-only---reliability-
backstop-rfi-summary---charles-river-associates.pdf 
[https://perma.cc/UM8V-FAC5] 
(“Charles 
River 
Associates Presentation”). 
56 Id. at 4. 
57 Id. at 5. 
58 Id. at 4-5.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 19 
 
 
 
II. 
BACKGROUND  
A. 
The Critical Issue Fast Path Stakeholder Process  
On January 16, 2026, the PJM Board issued a letter announcing its decision on the 
Critical Issue Fast Path Process (“CIFP”) addressing large load issues in PJM, which set 
forth the roadmap for a multi-pronged approach to addressing resource adequacy 
challenges, including “accelerat[ing] and execute[ing]” a backstop capacity procurement 
and “address[ing] cost allocation for any such procurement, including consideration of 
mechanisms that assign costs to those LSEs that are short as a result of incremental load 
growth within their service areas.”59  The NEDC/PJM Governors’ Principles were issued 
on the same day.   
In a Members Committee meeting convened one week later, on January 22, 2026, 
PJM’s President and CEO and the PJM Board raised the RBP with stakeholders and sought 
input regarding the timing and process for engaging stakeholders on issues relevant to a 
backstop procurement.  Based on feedback during the January 22 meeting, PJM’s President 
and CEO and the PJM Board initiated a series of discussions about RBP, which began in 
early February 2026 and concluded in March 2026.60  Simultaneously, through a survey, 
PJM sought and obtained detailed stakeholder feedback on the scope and process of an 
RBP.61  
 
59 January 2026 Board Letter at 6. 
60 
See 
Reliability 
Backstop 
Procurement 
Workshop, 
PJM 
Interconnection, 
L.L.C., 
https://www.pjm.com/committees-and-groups/workshops/rbpw [https://perma.cc/6RPD-YPZK] (last visited 
July 25, 2026).  
61 See Reliability Backstop Procurement Workshop: Survey Responses and Additional Feedback, PJM 
Interconnection, 
L.L.C., 
https://www.pjm.com/committees-and-groups/workshops/rbpw 
[https://perma.cc/6RPD-YPZK] (last visited July 25, 2026).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 20 
 
 
 
On April 8, 2026, the PJM Board issued a letter initiating the CIFP to engage 
stakeholders in the development of an RBP proposal (“RBP CIFP”).62  Subsequently, on 
May 19, 2026, the PJM Board issued a second related letter, directing that the scope of the 
RBP CIFP be expanded to incorporate a separate stakeholder process to identify and reduce 
large load in the PJM Region, when necessary, to maintain required RTO/Zonal Primary 
Reserves and Interconnection Reliability Operating Limits within limits if available 
economic generation is not sufficient.  This “connect and manage” solution, in its new 
iteration, is now referred to as an IRAS.63  The PJM Board determined that it would be 
appropriate to address both the RBP and IRAS in a single CIFP process in light of the 
substantive link between these two proposals.   
The expanded scope RBP and IRAS CIFP concluded on June 30, 2026, following 
eight days of stakeholder meetings over the course of three months.  On June 30, 2026, 
Stakeholders submitted advisory votes on 13 different RBP proposals.  Of the 13 proposals, 
only the voluntary RBP framework proposed by the Joint Electric Distribution Companies 
and Data Center Coalition (“Coalition RBP Proposal”) received greater than two-thirds 
sector-weighted member support.64   
 
62 Letter of David E. Mills, Interim President and CEO, PJM Interconnection, L.L.C. (Apr. 8, 2026), 
https://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-disclosures/2026/20260408-cifp-
rbp-initiation-letter.pdf [https://perma.cc/8LM5-9VX3] (stating the intent of the letter was to addresses the 
initiation of the Critical Issue Fast Path (CIFP) – Reliability Backstop Procurement (RBP) accelerated 
stakeholder process by the PJM Board).  
63 See Paula Conboy, PJM Board Chair, Reliability Backstop Procurement / Connect and Manage, PJM 
Interconnection, L.L.C., 1 (May 19, 2026), https://www.pjm.com/-/media/DotCom/about-pjm/who-we-
are/public-disclosures/2026/20260519-pjm-board-letter-re-reliability-backstop-procurement-connect-and-
manage-cifp.pdf [https://perma.cc/2CQC-8KYS]. 
64 PJM Members Committee, MC Voting Results for RBP Proposals Agenda Items 3L through 3X (June 30, 
2026), https://www.pjm.com/committees-and-groups/committees/mc [https://perma.cc/5CSQ-DP4K] (scroll 
to “Meeting Materials” and search for 2026, click on link for “6.30.2026 Special Meeting,” scroll to MC 
Voting Results – Agenda Items 3L to 3X and click on each to view the PDF) (last visited July 29, 2026).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 21 
 
 
 
B. 
PJM Board Determination 
The PJM Board reviewed the results of the June 30, 2026 stakeholder advisory 
votes.65  Ultimately, “[i]n light of the deteriorating resource adequacy outlook, and 
consistent with the PJM Board letter issued to stakeholders on May 19, 2026, the PJM 
Board “concluded that a voluntary subscription framework would not provide sufficient 
assurance that capacity equal to the identified near-term shortfall would actually be 
procured.”66   
On July 27, 2026, after weeks of careful deliberation, which considered the merits 
of the Coalition RBP Proposal, as well as other stakeholder proposals and various letters 
to the PJM Board, the PJM Board issued a decisional letter directing PJM to submit the 
RBP proposal set forth in this filing, and to also submit an IRAS proposal.67  PJM intends 
to submit the IRAS proposal in a separate FPA section 205 filing in the coming weeks.   
As for the RBP proposal that is the subject of this filing, the PJM Board 
“determined that PJM must take timely action within its control to begin restoring resource 
adequacy.”68  Thus, the PJM Board directed that PJM file with the Commission an RBP 
 
65 As PJM reported in a recent July 20, 2026 informational filing to the Commission, PJM sought additional 
feedback on the RBP proposal from stakeholders on specific topics through further polling, which concluded 
on July 10, 2026.  PJM Interconnection, L.L.C., PJM Informational Report on Stakeholder Processes 
Addressing Resource Adequacy for Large Loads, Docket No. EL26-67-000, at 4 (July 20, 2026) (citing PJM 
Interconnection, L.L.C., CIFP – Reliability Backstop Procurement / Connect & Manage, Summarized Poll 
Results 
(2026), 
https://www.pjm.com/-/media/DotCom/committees-groups/cifp-rbp/postings/cifp-poll-
results-with-comments.pdf [https://perma.cc/T2X8-NKGD]).   
66 Paula Conboy, Chair, PJM Board of Managers, Board Decisional Letter on Critical Issue Fast Path – 
Reliability Backstop Procurement and Connect and Manage, 1 (July 27, 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 
[https://perma.cc/V9Z7-83AH] 
(“PJM 
Board July 2026 Decisional Letter”). 
67 Id. 
68 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 22 
 
 
 
proposal that, unlike the voluntary subscription framework of the Coalition RBP Proposal, 
will procure for the identified near-term shortfall.69  At the same time, the PJM Board 
adopted various concepts from the Coalition RBP Proposal that received a sector-weighted 
majority of stakeholder support.  Specifically, the proposed (1) maximum volume weighted 
average of all selected RBP Sell Offers, (2) credit requirement for Load Serving Entities, 
and (3) opt-out from the RBP Initial Procurement Target all had their roots in the Coalition 
RBP Proposal.70  The proposal in this section 205 filing reflects the RBP framework 
ultimately approved by the PJM Board on July 27, 2026. 
C. 
PJM’s Large Load Matters  
The RBP proposal is just one of numerous filings that PJM has submitted or will 
shortly be submitting to the Commission, pursuant to section 205 of the FPA, to address 
the region’s resource adequacy issues.   
As of today’s filing, the following matters have already been filed with the 
Commission: 
• An Expedited Interconnection Track temporary pathway for advanced projects 
of significant size interconnected more quickly to address PJM’s urgent need 
for additional Capacity Resources by facilitating the interconnection of those 
new generation resources—outside of PJM’s Cycle Process—that commit to 
 
69 More specifically, the PJM Board directed that the RBP proposal set “an initial target equal to the capacity 
shortfall identified in the 2028/2029 Base Residual Auction, excluding Fixed Resource Requirement load 
and supply” and “reduced to reflect documented bilateral contracts and self-supply arrangements for new 
capacity serving new load.”  PJM Board July 2026 Decisional Letter at 2. 
70 Joint EDCs & Data Center Coalition (“Coalition”) Reliability Backstop Procurement Package Executive 
Summary, PJM Interconnection, L.L.C., https://www.pjm.com/-/media/DotCom/committees-groups/cifp-
rbp/2026/20260630/20260630-item-02f---joint-edcs-and-data-center-coalition---rbp---executive-
summary.pdf [https://perma.cc/YP8C-ASVB] (last visited July 31, 2026).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 23 
 
 
 
firm commercial in service dates and have a commitment from the Primary 
Siting Authority (or a state executive officer in certain circumstances) to 
expedite consideration of applicable siting, which was accepted by the 
Commission on June 9, 2026;71 
• An extension of a price collar on RPM Auction outcomes through the 
2029/2030 Delivery Year, which was accepted by the Commission on April 8, 
2026;72 
• A one-time, reliability-based expansion, known as the Reliability Resource 
Initiative, of the eligibility criteria for PJM’s Transition Cycle #2 of PJM’s 
existing interconnection queue, which the Commission accepted73 and resulted 
in PJM selecting 51 projects that can come online quickly and provide more 
than 9,300 MW of reliable capacity;74 
• An extension of the capacity must-offer requirement to all available Existing 
Capacity Resources so as to allow RPM Auction outcomes to more accurately 
reflect the actual quantity of Existing Generation Capacity Resources, while 
continuing to safeguard against the potential exercise of market power that may 
 
71 See PJM Interconnection, 195 FERC ¶ 61,197 at P1. 
72 See PJM Interconnection, L.L.C., 195 FERC ¶ 61,076, at P 51 (2026).   
73 See PJM Interconnection, L.L.C., 190 FERC ¶ 61,084, reh’g denied, 192 FERC ¶ 61,085 (2025). 
74 See PJM Interconnection, L.L.C., PJM Chooses 51 Generation Resource Projects To Address Near-Term 
Electricity Demand Growth, PJM Inside Lines (May 2, 2025), https://insidelines.pjm.com/pjm-chooses-51-
generation-resource-projects-to-address-near-term-electricity-demand-growth/ 
[https://perma.cc/4BBH-
YR3F].

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 24 
 
 
 
be exerted by the withholding of such resources, which was accepted by the 
Commission;75 and 
• A compliance filing and illustrative Tariff revisions to provide that the Eligible 
Customer taking transmission service on behalf of a co-located load may take 
a transmission service that reflects the co-located load’s ability and willingness 
to limit its use of the transmission system, which, if utilized, would reduce the 
amount of capacity required to meet the region’s resource adequacy needs.  The 
Commission ruled on PJM’s Tariff revisions and directed a future compliance 
filing to implement these new transmission services that PJM will soon 
submit.76 
The following filings aimed at addressing the impacts of new large loads on the 
PJM Region are forthcoming: 
• An “IRAS” proposal following the CIFP stakeholder process to facilitate the 
interconnection and integration of large loads that are not backed by capacity 
such that, in certain circumstances, the withdrawals from the transmission 
system by some new large loads would be reduced for resource adequacy 
purposes; 
 
75 PJM Interconnection, L.L.C., 190 FERC ¶ 61,117, order on reh’g, 191 FERC ¶ 61,221 (2025). 
76 See PJM Interconnection, L.L.C., 195 FERC ¶ 61,209 (2026).  On July 28, 2026, PJM submitted a motion 
to extend its compliance filing with respect to, among other things, the Tariff revisions implementing these 
new transmission services to allow for the concurrent development of the compliance language with the 
development of a new section 205 filing to propose new transmission services for Eligible Customers taking 
transmission services on behalf of large loads that are not part of a co-location arrangement.  PJM 
Interconnection, L.L.C., Motion for Extension of Time for Specified Compliance Requirements and Request 
for Expedited Treatment of PJM Interconnection, L.L.C., Docket Nos. EL25-49-002, et al. (July 28, 2026).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 25 
 
 
 
• A fulsome FPA section 205 filing addressing the issues the Commission raised 
in its June 18, 2026 Order to Show Cause that will set forth the non-rate terms 
and conditions for Eligible Customers to take transmission service on behalf of 
large loads that are willing and able to limit their energy withdrawals from the 
transmission system, which, if utilized, will reduce the amount of capacity 
required to meet the region’s resource adequacy needs; and 
• Future enhancements to reserve products and updated reserve demand curves 
to better account for ramping and uncertainty and better align reserve pricing 
with operational practice.77  
• In addition, PJM has undertaken the following initiatives: 
• Improved load forecasts that include state review of large load additions, 
addressing duplicative requests, the use of additional third-party review and 
increased transparency;78 and 
• Facilitating bilaterals by providing a voluntary matching service that helps 
connect potential buyers with sellers of capacity, as further explained below. 
III. 
THE PROPOSED REFORMS TO THE TARIFF AND THE RAA ARE JUST 
AND REASONABLE AND NOT UNDULY DISCRIMINATORY OR 
PREFERENTIAL 
A. 
Overview of the RBP 
The RBP is designed to be a one-time mechanism for procuring new capacity (i.e., 
UCAP MW only) to address the PJM Region shortfall observed in the BRA for the 
 
77 See PJM Interconnection, L.L.C., Informational Report on Stakeholder Process Addressing Resource 
Adequacy for New Large Loads of PJM Interconnection, L.L.C., Docket No. EL26-67-000, at 8 (July 20, 
2026). 
78 See January 2026 Board Letter at 2.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 26 
 
 
 
2027/2028 and 2028/2029 Delivery Years caused by the rapid load growth in the PJM 
Region.  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) Tariff, Attachment DD; (2) RAA, Article 7, 
sections 7.2B and 7.2C; (3) RAA, Schedule 8.1.D; and (4) Tariff, Definitions.  
The RBP represents a critical safety net designed to address current resource 
adequacy shortfalls.  The RBP’s function is limited to procuring the capacity needed to 
meet the reliability requirement shortfall observed in the 2028/2029 Delivery Year BRA 
and only to the extent that new load coming online in the 2027/2028 or 2028/2029 Delivery 
Years do not voluntarily procure sufficient new capacity to address that shortfall.79  In other 
words, the RBP is a one-time mechanism that will only procure the capacity necessary to 
cover any remaining shortfall from the 2028/2029 BRA after PJM has accounted for new 
capacity being brought by new load or that otherwise qualify for a limited opt-out from the 
RBP.  In this way (among others) it is consistent the NEDC/PJM Governors’ Principles, 
which call for a one-time auction followed by a subsequent “return to market 
fundamentals.”80 
In the context of RBP, this new capacity brought voluntarily by new load is referred 
to as Qualifying RBP Offset UCAP MW, a new defined term for capacity that meets 
parameters set forth in the proposed Tariff, Attachment DD, section 18.2.  Qualifying RBP 
Offset UCAP MW is further described in this transmittal letter, below, see infra 
 
79 In addition, as discussed below, PJM is proposing two limited opt-out provisions. 
80 NEDC/PJM Governors’ Principles at 1.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 27 
 
 
 
Part III.B.2.  To the extent the Commission accepts this filing, PJM is targeting to 
commence the procurement window for the one-time RBP on September 30, 2026.81   
1. 
The RBP is a Reliability Backstop solution tailored to meet a 
specific challenge in the context of a reliability requirement 
shortfall in PJM’s BRAs stemming, in part, from the influx of large 
loads, including data centers. 
According to the Commission, when market design measures alone prove 
insufficiently effective, “the Commission is willing to consider specific proposals to 
provide an appropriate last resort process such as an RTO/ISO administered auction to 
create a long-term commitment which can support cost-effective financing where the 
problem is projected to be a long-term one.”82  The RBP is such a proposal.   
The current PJM Tariff already contemplates the need for a backstop procurement 
when three consecutive auctions fail to procure the reliability requirement.83  But in this 
case, as the record reflects, there is a clear need for an RTO/ISO-administered backstop 
solution to be implemented now.  First, due to a variety of factors,84 the RPM has not 
procured sufficient capacity to meet the PJM Region Reliability Requirement two 
consecutive Delivery Years in a row.  Moreover, given the pace of new supply and the 
latest load forecast that will be used in the next BRA, in December 2026, all evidence 
points to the December auction also clearing short.   
 
81 In the event the Commission accepts this filing subject to modification, PJM will endeavor to commence 
the RBP as soon as practicable, but depending on what the changes are, the commencement date may not 
remain September 30, 2026. 
82 PJM Interconnection, L.L.C., 107 FERC ¶ 61,112, at P 21 (2004), order on reh’g, 110 FERC ¶ 61,053 
(2005). 
83 Tariff, Attachment DD, section 16. 
84 See 2027/2028 Base Residual Auction Reserve Target Shortfall Report, PJM Interconnection, L.L.C. (Feb. 
9, 
2026), 
https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-auction-info/2027-2028/2027-
2028-bra-reserve-target-shortfall-report.pdf [https://perma.cc/TA3Y-95AX] (“2027/2028 BRA Report”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 28 
 
 
 
Second, the undisputed evidence and observable trends to date argue for not simply 
waiting for a third auction to clear short .  it is well-documented and recognized that supply 
and demand in the PJM Region have converged, as a significant portion of PJM’s thermal 
generation fleet have retired while replacement resources are arriving at a slower pace than 
the unprecedented load growth, particularly in light of the exponential growth in demand 
from data centers.  Together, these factors have strained the RPM Auction’s ability to 
procure sufficient capacity to meet the PJM Region Reliability Requirement in recent 
capacity auctions.  Third, the NEDC/PJM Governors’ Principles expressly call for a 
backstop procurement auction to commence this September.  Fourth, the Commission was 
“encouraged by” and recently noted that PJM’s efforts to implement the RBP is among the 
“processes to ensure resource adequacy and faster interconnection.”85  In short, the 
evidence supports a clear need for a one-time RBP.86  Indeed, the NEDC/PJM Governors’ 
Principles urged PJM to “hold[] a Reliability Backstop Auction” and suggested that PJM 
had already received sufficient stakeholder input prior to running a procurement.87 
“[B]ackstops to . . . market design based solutions that are required to insure 
reliability” are nothing new to PJM.88  In fact, the RBP bears several significant similarities 
to the existing Reliability Backstop Auction provisions set forth in Tariff, Attachment DD, 
section 16.  A Reliability Backstop Auction would similarly “seek commitments of 
additional generation resources for a term of up to fifteen years,” where “PJM [would] 
 
85 June 2026 Order to Show Cause, 195 FERC ¶ 61,211 at P 103. 
86 PJM is also proposing to reset the Reliability Backstop Auction trigger by revising the Tariff, as discussed 
below, in Part III.G.1 of this transmittal letter. 
87 NEDC/PJM Governors’ Principles at 1. 
88 PJM Interconnection, 107 FERC ¶ 61,112 at P 21.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 29 
 
 
 
enter into long-term purchase agreements with sellers whose offers are accepted in the 
backstop auction.”89  In the Reliability Backstop Auction, “[e]ach accepted seller will be 
paid its offer price, less any payments the seller is entitled to receive for commitment of 
the same resource through the regular RPM auctions, and less any contributions to the fixed 
cost of its resource from the energy or ancillary service markets”90  That said, PJM is not 
simply relying on the Reliability Backstop Auction mechanism, which was proposed over 
20 years ago but has never once been used.   
The proposed RBP, although similar to the Reliability Backstop Auction in its 
intent to maintain resource adequacy and reliability for the Region, is tailored to address 
the specific circumstances surrounding the PJM Region’s present-day capacity shortfall 
stemming from large loads.  First, for example, the proposed RBP is intended to occur 
concurrently, on a parallel path, with an ongoing bilateral matching process that credits 
new capacity being brought by new large loads and therefore guards against double 
procurement in the RBP.  Second, the RBP recognizes affordability concerns of retail 
customers and, as explained below, the proposed RBP includes design features to address 
this.  Third, the RBP’s cost allocation mechanism has been intentionally developed to 
account for the boundary between federal and state jurisdiction and to recognize that, while 
the concern about potential cost shifts from large loads to residential and/or traditional 
industrial customers is a key and significant issue, the PJM states play a vital role in 
determining how to best ensure that costs are appropriately allocated to their respective 
 
89 PJM Interconnection, L.L.C., 115 FERC ¶ 61,079, at 61,245 (2006), order on reh’g, 119 FERC ¶ 61,318 
(2007), aff’d sub nom. Pub. Serv. Elec. & Gas Co. v. FERC, 324 F.App’x 1 (D.C. Cir. 2009).   
90 Id. at P 55.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 30 
 
 
 
retail, large load customers.  Fourth, the RBP was developed in the context of other 
approaches for addressing the issues posed by the rapid growth of large loads, including 
the forthcoming “IRAS” construct, a connect and manage-like proposal which 
contemplates operational rules for reducing large loads under certain emergency 
conditions.   
2. 
An ongoing bilateral matching process is a parallel path to 
supporting efforts to bring new capacity to PJM in order to meet the 
PJM Region Reliability Requirement shortfall.   
A primary role of the markets PJM operates is to provide a transparent price 
reference that informs and supports bilateral trading and Self-Supply activity.  Indeed, 
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.   
To streamline and support the efforts of PJM members to enter into bilateral 
arrangements for capacity, PJM, in partnership with PJM consultant Charles River 
Associates, has facilitated bilateral arrangements through a bilateral matching process with 
the aim of connecting supply of new capacity, i.e., new capacity resources, with new 
demand for that capacity, i.e., new load.  To be clear, participation in the bilateral matching 
process is non-binding and the matchmaking process itself does not impact rates, terms, or 
conditions.  Rather, the bilateral matchmaking process simply helps to facilitate voluntarily 
agreements so no Tariff changes are necessary to allow for this facilitation.    
The bilateral matching process is voluntary and iterative.  On June 9, 2026, the 
bilateral matching process began with a Request for Proposals, and initial matches are 
expected to be notified in or around August 2026.  PJM is not a party to these bilateral

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 31 
 
 
 
arrangements, nor has PJM placed any restrictions or requirements on the terms of these 
agreements.  Furthermore, bilateral matching is just one avenue in which supply and 
demand may voluntarily enter into arrangements to enable new load to bring their own new 
capacity.   
Capacity obtained through bilateral matching or other voluntary arrangements for 
new capacity, if reported to PJM within the RBP procurement window and supported by 
sufficient evidence, may be determined by PJM to be Qualifying RBP Offset UCAP MW.  
As discussed further, below, PJM may, as appropriate, based on the relevant evidence, 
reduce the Final RBP Target by the Qualifying RBP Offset UCAP MW and by the UCAP 
obligation value of load that have successfully requested and obtained an opt-out pursuant 
to proposed Tariff, Attachment DD, section 18.1(d).   
B. 
The RTO-Wide RBP Target Is Equal to the Initial RBP Target Minus 
Qualifying RBP Offset UCAP MW and Opt-Out UCAP MW (Proposed 
Tariff, Attachment DD, section 18.1). 
1. 
Initial and Final RBP Targets 
The RBP is designed to procure a target UCAP MW value of capacity on a 
region-wide basis.  The Initial RBP Target is the region-wide 2028/2029 Delivery Year 
reliability shortfall observed in the July 2026 BRA for Delivery Year 2028/2029, i.e., 
6,831.3 MW UCAP.91  Fixed Resource Requirement Entities are excluded from the Initial 
and Final RBP Targets as well as the RBP.92  The final RTO-wide procurement target, as 
 
91 See 2028/2029 BRA Report at 3 (“The [FRR] committed 10,863.8 MW UCAP to meet the FRR 
commitment.  The total procured capacity in the RTO, which includes RPM and FRR, is 149,181.6 MW 
UCAP or 6,831.3 MW UCAP below the RTO Reliability Requirement.”); proposed Tariff, Attachment DD, 
section 18.1(a). 
92 Proposed Tariff, Attachment DD, section 18.1(c).  The FRR, by design, is an opt-out of RPM, and the RBP 
is curing a gap that FRR load and FRR capacity are already removed from.  FRR load has already paid for

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 32 
 
 
 
proposed, is determined by subtracting both verified Qualifying RBP Offset UCAP MW 
and the unforced capacity obligation value of load with opt-outs.93   
Qualifying RBP Offset UCAP MW may be reported to PJM during the bid 
submission window, which will close three weeks after the window opening.  They must 
be accompanied by verified supporting evidence, and must meet the requirements set forth 
in proposed Tariff, Attachment DD, section 18.2, and discussed below, see infra Part 
III.B.2.    
The amount of capacity by which Qualifying RBP Offset UCAP MW may reduce 
the Initial RBP Target will be determined by PJM based on the applicable Effective Load 
Carrying Capability (“ELCC”) Class Ratings for the 2028/2029 Delivery Year BRA or, 
where the relevant resources do not have ELCC Class Ratings, the estimated unit-specific 
UCAP values for such resources.94  The amount of capacity by which Qualifying RBP 
Offset UCAP MW may reduce the Initial RBP Target will also be capped at the Load 
Adjustment for each Electric Distributor zone/area amount of summer 2028 demand as set 
forth in the load forecast.95 
Additionally, the region-wide Initial RBP Target will be further reduced by Opt-
Out UCAP MW to the extent that an Electric Distributor, whose rates are not regulated by 
the state (e.g., cooperatives or municipal utilities), that is unable to allocate costs associated 
 
resource adequacy through the FRR Plan.  Allocating RBP Charges to FRR load would, in essence, require 
that they pay twice for capacity it has already procured. 
93 Proposed Tariff, Attachment DD, section 18.1(b). 
94 Proposed Tariff, Attachment DD, section 18.2(d); RAA, Schedule 9.2, section D(1)(b) (on Accredited 
UCAP for resources with unit-specific UCAP values). 
95 Proposed Tariff, Attachment DD, section 18.2(e).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 33 
 
 
 
with capacity bid submission in the RBP to large loads, submits a request to PJM to opt-
out from the RBP within the bid submission window and provides relevant information 
and written support.  In addition, an Electric Distributor may also request to opt out of the 
RBP for an associated MW quantity of load that participates in a peak shaving adjustment 
program where such Electric Distributor’s zone/area addresses their capacity needs through 
peak shaving adjustment programs that are codified in state law and meet the requirements 
set forth in Tariff, Attachment DD-2. 
 
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 region-wide shortfall.  In other words, PJM is not 
proposing to match specific supply to specific demand or apply locational constraints in 
the RBP.  As Ms. Danielle Croop, Senior Manager in the Market Design group for PJM, 
testifies on behalf of PJM, while “PJM recognizes there are locational considerations at 
large for resource adequacy, and these constraints are modeled in the [RPM,]” 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.”96  
By contrast, Ms. Croop testifies, “PJM 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 
 
96 Affidavit of Ms. Danielle Croop on Behalf of PJM Interconnection, L.L.C. (Attachment C) ¶ 8 (“Croop 
Aff.”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 34 
 
 
 
commitments.”97  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 ten and fifteen years from now.  Moreover, 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 RTO.  Going forward, the PJM Regional 
Transmission Expansion Plan (“RTEP”) process annually studies and addresses any 
transmission upgrades needed to ensure the ongoing deliverability of capacity resources.  
Load deliverability is also assessed as part of the RTEP process, which will identify 
transmission needs as load patterns change.”98  In short, inclusion of a speculative 15-year 
forward locational capacity requirement at this point in time would simply ignore the role 
of PJM’s interconnection and planning process as the means to ensure deliverability of 
capacity resources to load throughout the PJM Region. 
In short, the RBP aims to procure RBP Resources for up to a 15-year fixed term.  
Since PJM does not calculate locational parameters 15 years out, procuring resources on a 
locational basis would be impractical.  Therefore, the Final RBP Target is not so granular 
as to assign procurement targets for specific Zones or specific Electric Distributor 
zones/areas.99  However, as described below, see infra Part III.E, the Final RBP Target will 
serve as an initial input to the RBP cost allocation methodology.   
 
97 Id. 
98 Id. ¶ 9. 
99 For purposes of cost allocation as discussed below, see infra Part III.E, PJM will allocate cost responsibility 
to Electric Distributor zones/areas, to be further suballocated by PJM and the states.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 35 
 
 
 
2. 
Qualifying 
RBP 
Offset 
UCAP 
MW 
(proposed 
Tariff, 
Attachment DD, section 18.2) 
Qualifying RBP Offset UCAP MW is new capacity voluntarily brought on to the 
PJM system by new load that meets certain characteristics and parameters set forth in the 
proposed Tariff, as supported by evidence verified by PJM.100  Where Electric Distributors 
and/or other entities report Qualifying RBP Offset UCAP MW to PJM with the requisite 
supporting evidence, PJM may reduce the region-wide Initial RBP Target by the quantity 
of Qualifying RBP Offset UCAP MW, where appropriate.101  In other words, the Initial 
RBP Target may be decremented by the quantity of Qualifying RBP Offset UCAP MW. 
a. 
New load and new demand 
i. 
Load (demand) must be new (proposed Tariff, 
Attachment DD, section 18.2(c)) 
Importantly, Qualifying RBP Offset UCAP MW can offset the RBP procurement 
if it serves new load.  “New” load, for purposes of the RBP, will be load that has an 
executed electric service agreement or transmission service agreement, indicating that the 
load will be coming online in the 2027/2028 through the 2028/2029 Delivery Year. 
ii. 
Capacity must be new (proposed Tariff, Attachment 
DD, section 18.2(a)) 
Just as Qualifying RBP Offset UCAP MW must be supported by a showing that the 
load being served is new, supply must likewise demonstrate that it is “new” capacity.  To 
 
100 “Qualifying RBP Offset UCAP MW” is also a proposed, new defined term in the Tariff.  Proposed Tariff, 
Definitions – Qualifying RBP Offset UCAP MW (defining “Qualifying RBP Offset UCAP MW” as the 
“unforced capacity that:  (i) pursuant to Tariff, Attachment DD, section 18.2, has not received an RPM 
commitment or been committed in an FRR Plan as of the commencement of the Reliability Backstop 
Procurement, (ii) is supplied by eligible Capacity Resources in accordance with Tariff, Attachment DD, 
section 18.2(b), and (iii) is supported by evidence, in accordance with Tariff, Attachment DD, section 
18.2(c)”). 
101 Proposed Tariff, Attachment DD, section 18.2(c).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 36 
 
 
 
be deemed new, the capacity must have neither previously received a commitment in the 
RPM nor been previously committed in an FRR plan, as of the beginning of the RBP in 
September, 2026.102   
Eligible supply may be:  (i) a new build generation resource including new 
resources that obtain Capacity Interconnection Rights (“CIR”) transferred from deactivated 
resources or resources that have announced deactivation as of April 10, 2026; (ii) the 
incremental capacity created by an uprate of existing Generation Capacity Resources, but 
only to the extent such incremental capacity is created through an increase in such 
Generation Capacity Resource’s installed capacity and increase in CIRs associated with 
that Generation Capacity Resource; (iii) the incremental capacity created by the utilization 
of Surplus Interconnection Service; (iv) repowering of a deactivated generation resource 
that deactivated prior to April 10, 2026; (v) 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 (vi) Planned Demand 
Resource or Planned Distributed Energy Resources (“DER”) Capacity Aggregation 
Resources, as described in the RAA, Schedule 6 and Schedule 6.2.103  
Qualifying RBP Offset UCAP MW provided by new capacity through bilateral 
contracts or Self-Supply generation  must be, as described in the following section of this 
transmittal letter, matched with new load.104  Alternatively, new load that provides its own 
Qualifying RBP Offset UCAP MW by participating as an Annual Demand Resource or 
 
102 Proposed Tariff, Attachment DD, section 18.2(a). 
103 Proposed Tariff, Attachment DD, section 18.2(b). 
104 Proposed Tariff, Attachment DD, sections 18.2(c)(i)-(ii).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 37 
 
 
 
DER Capacity Aggregation Resource must do so “starting in the 2028/2029 Delivery Year 
Second Incremental Auction and continuing through the 2032/2033 Delivery Year.”105  
However, new load participating as an Annual Demand Resource or DER Capacity 
Aggregation Resource is permitted to subsequently replace UCAP MW provided through 
participation as an Annual Demand Resource or DER Capacity Aggregation Resource by 
purchasing “Qualifying RBP Offset UCAP MW that are eligible generation or storage 
resources.”106  
iii. 
Matching new load with new capacity supports 
reliability 
and 
avoids 
over-procurement, 
under-procurement, and double-counting (proposed 
Tariff, Attachment DD, section 18.2(b)) 
Decreasing the Initial RBP Target by only the capacity that meets the requirements 
of Qualifying RBP Offset UCAP MW prevents double procurement of the capacity 
shortfall and avoids situations where load could effectively pay twice for capacity.  The 
restrictions on Qualifying RBP Offset UCAP MW also help protect against 
under-procurement by preventing a decrement to the Initial RBP Target from interfering 
with PJM’s ability to maintain reliable operation of the system.   
More specifically, requiring Qualifying RBP Offset UCAP MW to be paired with 
new load recognizes that the Initial RBP Target, based on the PJM Region Reliability 
Requirement shortfall of 6,831.3 MW, is derived from the forecasted demand for the period 
from 2027 up through the start of the 2028/2029 Delivery Year (or, for purposes of Demand 
Resources and DER Aggregation Resources, through the second Incremental Auction).   
 
105 Proposed Tariff, Attachment DD, section 18.2(c)(iii). 
106 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 38 
 
 
 
Thus, the Initial RBP Target should be decremented only by a quantity of capacity 
(supply) that was not already counted as supply for the 2027/2028 and 2028/2029 Delivery 
Years (i.e., capacity not already committed in PJM RPM).  The Initial RBP Target should 
also only be decremented by new capacity that serves load (demand) that was counted in 
the forecast.  A simplified example demonstrates how the new load and new capacity 
requirements avoid under- and over-counting the RBP Target:   
Included in the Load Adjustment Forecast:   
Electric Distributor (ED) A (15 MW of Demand), Including Demand from 
Load B 
------------------ 
Initial RBP Target = 10 MW Shortfall (i.e., the MW short of the PJM 
Region Reliability Requirement from the 2028/2029 BRA)   
Then, 
Load B (Within ED zone/area A) Brings Resource C (2 MW 
of Supply, commercial operation date 2030)  
Resource C has not previously been a PJM capacity resource 
or committed in FRR   
If Resource C is otherwise eligible to serve as Qualifying 
RBP Offset UCAP MW, Initial RBP Target Decremented by 
2 MW → Revised RBP Target = 8 MW 
When new load that contributed to the capacity shortfall in PJM has brought new 
capacity—i.e., capacity not previously counted as part of the calculation of PJM’s capacity 
shortfall—the impacts of the new load and the new capacity effectively cancel each other 
out.  Decrementing the Initial RBP Target by the quantity of Qualifying RBP Offset UCAP 
MW allows PJM to “right-size”107 the RBP Target while addressing the systems resource 
adequacy.  
 
107 See Building for the Future Through Electric Regional Transmission Planning and Cost Allocation, Order 
No. 1920, 187 FERC ¶ 61,068 at PP 10, 34, order on reh’g & clarification, Order No. 1920-A, 189 FERC

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 39 
 
 
 
b. 
Signed bilateral contracts or Self-Supply generation 
resources 
(proposed 
Tariff, 
Attachment 
DD, 
sections 18.2(c)(i) and 18.2(c)(ii)) 
Qualifying RBP Offset UCAP MW may be supported by signed bilateral contracts 
for at least five Delivery Years108 or by Self-Supply generation that is in a RERRA-
approved or accepted integrated resource plan with either associated generation in the PJM 
interconnection queue or signed bilateral contracts for at least five Delivery Years.109   
To serve as Qualifying RBP Offset UCAP MW, both signed bilateral contracts and 
Self-Supply must be supported by documentation of an expected online date of no later 
than June 1, 2032.  Furthermore, the evidence must demonstrate that the new capacity is 
matched with load that has an executed electric service agreement or transmission service 
agreement indicating that the load will be online in the 2027/2028 or 2028/2029 Delivery 
Years.   
Both signed bilateral contracts for Qualifying RBP Offset UCAP MW and signed 
bilateral contracts for new resources by Self-Supply Entities in a RERRA-approved or 
accepted integrated resource plan, must have a minimum term of at least five Delivery 
Years.  A five-year minimum term is balanced.  Capacity with a bilateral contract of at 
least five years is capacity that will address the reliability shortfall and is not transitory.  
Furthermore, a five-year term is not so lengthy as to undermine the flexibility needed for 
commercial contracting or to pose a significant barrier to eligibility for Qualifying RBP 
 
¶ 61,126 (2024), order on reh’g & clarification, Order No. 1920-B, 191 FERC ¶ 61,026 (2025), appeals 
pending sub nom. Appalachian Voices v. FERC, Nos. 24-1650, et al. (4th Cir. July 16, 2024). 
108 Proposed Tariff, Attachment DD, section 18.2(c)(i). 
109 Proposed Tariff, Attachment DD, section 18.2(c)(ii).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 40 
 
 
 
Offset UCAP MW, in recognition of the fact that bilateral agreements may not need to be 
longer than five years to develop new capacity.     
Decrementing the Initial RBP Target by new resources reflected in bilateral 
contracts or being developed by Self-Supply Entities that are already in approved 
integrated resource plans is appropriate, as these new resources have already been 
procured. 
c. 
Loads participating as Annual Demand Resources or DER 
Aggregation Resources (proposed Tariff, Attachment DD, 
section 18.2(c)(iii)) 
In the alternative, Qualifying RBP Offset UCAP MW may be supported by a signed 
commitment between a Curtailment Service Provider or DER Aggregator and new load.  
In this case, the new load must be supported by an executed electric service agreement or 
transmission service agreement that shows that the new load will either support its full MW 
quantity by:  (a) participating as Annual Demand Resources or DER Aggregation 
Resources at new locations starting in the 2028/2029 Delivery Year Second Incremental 
Auction and a must-offer requirement in RPM through 2032/2033 Delivery Year or (b) 
purchasing eligible replacement Qualifying RBP Offset UCAP MW. 
d. 
Capacity eligible to provide Qualifying RBP Offset UCAP 
MW (proposed Tariff, Attachment DD, section 18.2(b)) 
The universe of capacity that is eligible to serve as Qualifying RBP Offset UCAP 
MW that may decrement the Initial RBP Target is relatively large.  Qualifying RBP Offset 
UCAP MW may be provided by new generation, Energy Storage Resources, Planned 
Demand Resources, or Planned DER Capacity Aggregation Resources.110  Furthermore, to 
 
110 Proposed Tariff, Attachment DD, sections 18.2(b), (c).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 41 
 
 
 
be clear, eligible capacity is not limited to capacity obtained through the recent, concurrent 
bilateral matching process, which is explained in Part III.A.2 above.  In addition, 
Qualifying RBP Offset UCAP MW are not limited to capacity supplied by newly 
constructed resources.  For example, eligible resources may include incremental capacity 
created by an uprate of existing Generation Capacity Resources, incremental capacity from 
Surplus Interconnection Service, and repowering of deactivated generation resources that 
retired as of April 10, 2026, which is the day that this particular eligibility requirement was 
first posted.111   
The categories of capacity that may provide Qualifying RBP Offset UCAP MW are 
relatively expansive, as decrementing Qualifying RBP Offset UCAP MW avoids 
double-counting for load that is included in the Initial RBP Target and planning to bring 
its own capacity to the system.  That said, the categories of capacity eligible to serve as 
Qualifying RBP Offset UCAP MW are not so expansive as to cause PJM to decrement the 
Initial RBP Target by UCAP MW that are not “new” or not sufficiently certain to be 
available when called upon and reduce the resource adequacy shortfall outside the RBP.  
Qualifying RBP Offset UCAP MW must therefore be accompanied by supporting 
evidence, which PJM assesses before determining whether new capacity should be deemed 
Qualifying RBP Offset UCAP MW and permitted to decrement the initial procurement 
target.   
 
111 An April 10, 2026, 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.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 42 
 
 
 
It is also worth noting that Qualifying RBP Offset UCAP MW has been deliberately 
designed to be more inclusive than the resources that qualify to sell RBP UCAP MW, 
which PJM is proposing to call RBP Resources.112  As discussed below, see infra Part 
III.C.3, while resources that bring Qualifying RBP Offset UCAP MW reduce the Final 
RBP Target, those resources do not hold any commitment or receive settlement through 
PJM in the RBP.  In contrast, RBP Resources procured through the RBP will be paid based 
on a pay-as-bid basis for a fixed, 15-year term, and have obligations such as a must-offer 
requirement for capacity for the term of the commitment.  RBP Resource requirements are 
more stringent, thus narrowing the universe of resources that may voluntarily sell RBP 
UCAP MW to those that have successfully demonstrated a high likelihood of providing 
stable, long-term capacity.  In exchange, RBP Resources receive price certainty and 
stability through the RBP.113  The distinction between Qualifying RBP Offset UCAP MW 
and RBP UCAP MW provided by RBP Resources is discussed in greater detail below. 
e. 
Electric Distributors and other entities provide evidentiary 
support for Qualifying RBP Offset UCAP MW (proposed 
Tariff, Attachment DD, section 18.2(c)) 
PJM is proposing to require that Electric Distributors provide reports and evidence 
of Qualifying RBP Offset UCAP MW in each of their respective zones/areas under the new 
proposed Tariff provisions.  As the Commission has previously held, Electric Distributors 
serve as “the party with the distribution and metering facilities defining a zone/area and 
 
112 Proposed Tariff, Definitions – RBP Resources (defining “RBP Resources” as “generation resources, 
Energy Storage Resources, Demand Resources, or DER Aggregation Resources, as set forth in Tariff, 
Attachment DD, section 18.5, offered to provide RBP UCAP MW from the Reliability Backstop 
Procurement, in accordance with Tariff, Attachment DD, section 18”). 
113 See Croop Aff. ¶¶ 14-16.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 43 
 
 
 
responsible for reporting load information to PJM.”114  However, so as to not inadvertently 
limit sources of relevant and reliable information, PJM will also accept reports and 
evidence of Qualifying RBP Offset UCAP MW provided during the RBP bid submission 
window by other jurisdictional, as well as non-jurisdictional entities, including, but not 
limited to, Transmission Owners, LSEs, interconnecting customers, large loads, and state 
regulatory agencies.  Commission precedent has previously supported PJM’s decision to 
not limit the reporting of Load Adjustments to Electric Distributors.115   
PJM acts within its authority to collect, review, and consider information from both 
jurisdictional and non-jurisdictional entities to the extent that the information is relevant to 
Commission-jurisdictional services and rates.  First, such information is “in connection 
with” and “directly affecting” wholesale capacity market rates.116  In this case, the 
information that PJM seeks to collect will impact the Final RBP Target.  Indeed, an 
analogous practice can be found in longstanding requirements applicable to demand 
resources, as set forth in Order No. 719-A.117  In that order, the Commission prohibited 
PJM and other RTOs/ISOs from accepting bids from Curtailment Service Providers that 
aggregated demand response of customers of utilities distributing below a MW per hour 
threshold unless otherwise permitted by an appropriate retail authority.118  To comply with 
Order No. 719-A, the Commission required that PJM and other RTOs/ISOs review 
 
114 PJM Interconnection, L.L.C., 188 FERC ¶ 61,200, at P 40 (2024). 
115 Id. at PP 22, 44. 
116 EPSA, 577 U.S. at 278-79; FPA section 201(b), 16 U.S.C. § 824(b). 
117 Wholesale Competition in Regions with Organized Electric Markets, Order No. 719-A, 128 FERC 
¶ 61,059, order on clarification, Order No. 719-B, 129 FERC ¶ 61,252 (2009). 
118 Order No. 719-A at P 60; PJM Interconnection, L.L.C., 135 FERC ¶ 61,211, at P 3 (2011).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 44 
 
 
 
evidence and information concerning end-use customer participation in load response 
programs.  In PJM’s case, “when an LSE or Electric Distribution Company does not 
present evidence that the Retail Authority permits or conditionally permits demand 
response activity, the registration will not be processed until evidence of Retail Authority 
authorization for the resource’s participation in PJM’s load response programs is provided 
to PJM within the established deadlines.”119  
Second, in the Commission’s June 2026 Order to Show Cause, the Commission 
expressly required PJM and the PJM Transmission Owners to post and regularly update 
data and details concerning large load additions, including “detailed information regarding 
the extent to which requests for transmission service by Eligible Customers on behalf of 
large loads necessitate Network Upgrades to accommodate the transmission service to 
Eligible Customers on behalf of large loads.”120  Likewise, under the RBP, PJM is 
proposing to collect, review, verify, and evaluate information to determine if the Final RBP 
Target should be adjusted downward to reflect arrangements entered into voluntarily by 
new loads to obtain new capacity.    
3. 
Opt-out (proposed Tariff, Attachment DD, section 18.1(d)) 
The Final RBP Target will also be decremented where an Electric Distributor 
zone/area elects to opt-out of procuring through the RBP for a particular zone/area in one 
of two specific and narrow circumstances.  First, an opt-out may be requested where the 
Electric Distributor’s zone/area has rates that are not regulated by the states and is unable 
to address cost allocation associated with capacity procured in the backstop.  This opt-out 
 
119 PJM Interconnection, 135 FERC ¶ 61,211 at P 3. 
120 June 2026 Order to Show Cause, 195 FERC ¶ 61,211 at P 74.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 45 
 
 
 
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).  This narrow opt-out is designed to address a 
limited regulatory gap faced by cooperatives and municipal utilities whose rates are not 
regulated by the states.  During the stakeholder process, cooperatives raised the concern 
that Electric Distributors in a retail choice state 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 particular large load included in the forecast were to fail to 
materialize.  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.  
Second, PJM is also proposing another narrow opt-out to permit Electric 
Distributors to decrement the Initial RBP Target by up to the associated MW quantity of 
load that participates in a peak shaving adjustment program codified in state law (e.g., NJ 
A796),121 where an Electric Distributor’s zone/area addresses its capacity needs through 
such a program.  To support an opt-out, the peak shaving adjustments must meet all 
applicable requirements established in Tariff, Attachment DD-2. 
 
121 See 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, 
https://www.billtrack50.com/billdetail/1954539 (last updated July 7, 2026).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 46 
 
 
 
Reducing the Final RBP Target by the quantity of this opt-out is similar to reducing 
the target by the quantity of new load contracting for new capacity that would qualify as a 
Qualifying RBP Offset UCAP MW.  While there is no accreditation value for peak shaving 
adjustment, the opt-out effectively recognizes bilateral agreements between load and peak 
shaving adjustment programs. 
To reflect the UCAP MW of the opt-out, the Initial RBP Target will be decremented 
by the amount specified by the Electric Distributor.  Importantly, however, even if the 
Electric Distributor zone/area qualifies for and receives an opt-out from the RBP, the load 
in that zone/area may be subject to load reduction under the forthcoming proposal to 
implement an IRAS. 
C. 
The Procurement Process:  RBP Resources, Offers, RPM Must Offer, 
Clearing, Settlement, and Cost Responsibility (Proposed Tariff, 
Attachment DD, sections 18.4, 18.5, and 18.6) 
1. 
The scope of the RBP (proposed Tariff, Attachment DD, 
section 18.4) 
 
PJM is proposing new Tariff provisions to describe the procurement process under 
the RBP and to broadly address:  (1) who may participate in the RBP; (2) what the RBP 
aims to procure; (3) the length of the procurement term; (4) when the RBP will take place; 
and (5) whether and when RBP Resources participating in the RBP may, in the alternative, 
enter into arrangements for Qualifying RBP Offset UCAP MW. 
First, participants in the RBP are (1) sellers with RBP Sell Offers122 submitted on 
behalf of RBP Resources; and (2) PJM Settlement, Inc. (“PJMSettlement”), acting as a 
 
122 Proposed Tariff, Definitions – RBP Sell Offer (defining “RBP Seller Offer” as “an offer to sell RBP 
Resources in the Reliability Backstop Procurement”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 47 
 
 
 
counterparty on behalf of buyers, i.e., load.  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.123  There is broad consensus among stakeholders that PJM should serve as the 
counterparty that directly procures capacity on behalf of buyers.124  Furthermore, relying 
on PJMSettlement as the counterparty mirrors the existing structure of the Reliability 
Backstop Auction set forth in Tariff, Attachment DD, section 16.4(a).125 
Second, PJM will seek to procure RBP Resources up to the UCAP MW value of 
the Final RBP Target.126  RBP Resources are limited to generation, Energy Storage 
Resources, Demand Resources, or DER Aggregation Resources that meet the 
characteristics described in the proposed Tariff.127  Additional details concerning the 
requirements that resources must meet to be RBP Resources are set forth in proposed 
Tariff, Attachment DD, sections 18.5(b) through 18.5(e).   
 
123 
PJM 
Interconnection 
Subsidiaries, 
PJM 
Interconnection, 
L.L.C. 
(Sep. 
5, 
2025), 
https://pjm.my.site.com/publicknowledge/s/article/PJM-Interconnection-Subsidiaries?language=en_US 
[https://perma.cc/B2QA-S7RS].  
124 Indeed, as set forth in the PJM RBP Matrix, of the 13 RBP proposals put forth during the CIFP, seven of 
the proposals identified PJMSettlement as the counterparty.  In addition, two of the proposals took no position 
on the matter.  See PJM Interconnection, L.L.C., MC Voting Results for RBP Proposals Agenda Items 3L 
through 
3X 
(June 
30, 
2026), 
https://www.pjm.com/committees-and-groups/committees/mc 
[https://perma.cc/5CSQ-DP4K] (scroll to “Meeting Materials” and search for 2026, click on link for 
“6.30.2026 Special Meeting,” scroll to MC Voting Results – Agenda Items 3L to 3X and click on each to 
view the PDF) (last visited July 29, 2026). 
125 Tariff, Attachment DD, section 16.4(a) (“PJMSettlement shall be the Counterparty to the capacity 
transaction resulting from committed Capacity Resources clearing the Reliability Backstop Auction.”). 
126 Proposed Tariff, Attachment DD, section 18.4. 
127 Proposed Tariff, Definitions – RBP UCAP MW (defining “RBP UCAP MW” as “unforced capacity that 
is eligible to be offered in the Reliability Backstop Procurement, in accordance with Tariff, Attachment DD, 
section 18”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 48 
 
 
 
Third, RBP Sell Offers submitted in the RBP are offers of RBP UCAP MW for a 
fixed 15-Delivery Year term128 if the project is expected to commence commercial 
operation beginning with the 2028/2029 Delivery Year.129  RBP Resources with a 
commercial operation date later than the 2028/2029 Delivery Year will be committed for a 
shorter term, representing the remainder of the 15-Delivery Year term of the RBP 
commitment period through the end of the 2042/2043 Delivery Year.130  The 15-Delivery 
Year term is informed by the NEDC/PJM Governors’ Principles, which seeks “[r]evenue 
[c]ertainty to [n]ew [g]eneration” through “15-year price certainty for new capacity 
resources.”131 
Fourth, the RBP submission window is planned to open upon Commission 
acceptance of this submittal (with a targeted date of September 30, 2026) and close three 
weeks after, and the subsequent clearing and selection process will take place thereafter 
and conclude six weeks following the closing of the offer submission window.  PJM will 
notify RBP Sellers that have been committed as soon as practicable upon the conclusion 
of the RBP.132  Assuming the Commission accepts this FPA section 205 filing within 60 
days, i.e., by September 29, 2026, and no new major concerns or hurdles arise, PJM intends 
to commence the RBP on September 30, 2026.133  The timing of the commencement of the 
 
128 Proposed Tariff, Attachment DD, section 18.4. 
129 Id. 
130 Id. 
131 NEDC/PJM Governors’ Principles at 1; see also Tariff, Attachment DD, section 16.4(a) (“The Reliability 
Backstop Auction shall obtain commitments of additional Generation Capacity Resources (or, as applicable, 
additional Base Load Generation Resources) for a term of up to fifteen (15) Delivery Years.”). 
132 Proposed Tariff, Attachment DD, section 18.4. 
133 Proposed Tariff, Attachment DD, section 18.4.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 49 
 
 
 
RBP is informed by: (1) the NEDC/PJM Governors’ Principles, which urged that the 
procurement should occur “no later than September 2026[,]”134 and by (2) the desire for 
PJM to finalize selection and commitments of RBP Resources prior to the opening of the 
2029/2030 Delivery Year BRA, scheduled for December 2026. 
Fifth, RBP Sell Offers are considered binding.135  In other words, RBP Resources 
that are the subject of an RBP Sell Offer are not permitted to exit the RBP to enter bilateral 
arrangements, either through bilateral matching or otherwise, inclusive of arrangements 
that would be considered Qualifying RBP Offset UCAP MW.136  However, to the extent 
that the results of the RBP indicate that an RBP Resource was not committed in the RBP, 
such resource may subsequently enter into bilateral arrangements for Qualifying RBP 
Offset UCAP MW or otherwise.137  In summary, the RBP Sell Offer is a binding offer once 
any PJM-identified deficiencies are cured and until the conclusion of the RBP.  RBP Sellers 
cannot enter into bilateral agreements for the same project unless, following the conclusion 
of the procurement process, the project is not committed in the RBP.   
2. 
Overview of seller and buyer obligations  
Table 1, below, provides an overview of seller and buyer responsibilities.  Sellers 
eligible to participate in the RBP, i.e., RBP Resources or Market Participants selling RBP 
UCAP MW of RBP Resources must:  (1) meet collateral requirements prior to participating 
in the RBP; (2) support eligibility to provide capacity; (3) provide capacity; (4) cover 
 
134 NEDC/PJM Governors’ Principles at 1. 
135 See proposed Tariff, Attachment DD, section 18.4. 
136 See id. 
137 See proposed Tariff, Attachment DD, section 18.2(c).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 50 
 
 
 
penalties for any capacity shortfalls; and (5) bear responsibility for defaults.  Likewise, 
buyers, i.e., LSEs, must:  (1) meet collateral requirements prior to each relevant Delivery 
Year; (2) cover the cost of RBP UCAP MW in accordance with the allocation of RBP 
Charges; and (3) bear responsibility for defaults.    
Table 1. RBP Sellers and Buyers: Payments and Non-payments (Tariff Provisions) 
 
Seller (Supply)  
Buyer (Demand)  
Credit/Collateral 
Requirements 
Credit Requirements Prior to 
Participation in RBP 
(Tariff, Attachment DD  
§ 18.8(a)) 
Credit Requirements Prior to 
Delivery Year (Tariff, 
Attachment DD § 18.8(b)) 
Provision of RBP 
UCAP MW/ 
RBP Charges 
Eligibility and Obligations to 
Provide Capacity (Tariff, 
Attachment DD §§ 18.5, 18.6) 
UCAP MW Eligible to Settle 
as CfD (Tariff, Attachment 
DD 
§ 18.5(g)(i)) 
Settlement of RBP Credits 
(Tariff, Attachment DD  
§ 18.5(g)(ii)) 
Responsibility to Pay (RAA, 
7.2B) 
Settlement of RBP Charges 
 (Tariff, Attachment DD  
§ 18.5(g)(iii)) 
Cost Allocation (Tariff, 
Attachment DD  
§ 18.3) 
RBP UCAP MW 
shortfalls, RBP 
shortfall charges, 
and Associated 
Credits to Buyers 
Non-payment for RBP UCAP 
MW that Seller Is Short 
(Tariff, Attachment DD  
§ 18.6(c)  
RBP shortfall charges for 
Failure to Reach Commercial 
Operation in Delivery Year 
for which RBP Resource 
Committed (Tariff, 
Attachment DD § 18.6(d)) 
Allocation of RBP shortfall 
credits to LSEs based on pro-rata 
share of Final RBP Target 
(Tariff, Attachment DD  
§ 18.3(b)(iv); RAA, Section 
7.2B) 
Default 
(nonpayment) 
Decrease in RBP Credits 
Where Nonpayment of RBP 
shortfall charges (Tariff, 
Attachment DD § 18.9) 
Cover Nonpayment of RBP 
Charges (Tariff, Attachment DD 
§ 18.9)

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 51 
 
 
 
3. 
Resources eligible to participate in the RBP must bring new 
capacity to PJM (proposed Tariff, Attachment DD, sections 18.5(a) 
through 18.5(d))  
The RBP is focused on procuring new capacity.  Thus, to be eligible to be offered 
into the RBP, a resource must:  (1) never have been committed to provide capacity;138 
(2) not have been the subject of a notice of intent to participate in an RPM Auction prior 
to and including the 2028/2029 Delivery Year, but if so, must have offered and not cleared 
any RPM Auction;139 (3) have a commercial operation date, or other reasonable 
expectation of being in service or otherwise be able to provide capacity, by no later than 
June 1, 2032;140 and (4) not be supplying Qualifying RBP Offset UCAP MW.141  As further 
explained below, neither an RBP commitment nor participation in the RBP will impact the 
requirement that a resource that is already the subject of a notice of intent be offered in the 
2029/2030 BRA.  The capacity is needed and should be offered. 
RBP is designed to attract new supplies of capacity (i.e., new ICAP), not merely 
incremental resource efficiencies, to address the current capacity shortfall and provide a 
stable, long-term source of capacity.  Resources procured through the RBP must 
demonstrate a high degree of certainty of achieving commercial operation within the next 
few years and be available to provide capacity until the end of a fixed, 15-year term.  And, 
 
138 See, e.g., proposed Tariff, Attachment DD, section 18.5(a)(ii) (The resource “[h]as not received a capacity 
commitment or been committed in an FRR Plan as of the commencement of the Reliability Backstop 
Procurement.”). 
139 See proposed Tariff, Attachment DD, section 18.5(a)(iv) (The resource “[t]o the extent the subject of a 
notice of intent for the 2028/2029 Base Residual Auction, must have offered and not cleared in the 2028/2029 
Base Residual Auction.”). 
140 See Proposed Tariff, Attachment DD, section 18.5(a)(i). 
141 See Proposed Tariff, Attachment DD, section 18.5(a)(iii).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 52 
 
 
 
importantly, resources procured through the RBP will be paid under the RBP framework, 
not through bilateral or similar arrangements.  
The Final RBP Target, on the other hand, is an input in the RBP, setting the desired 
amount of UCAP MW to be procured.  Thus, as discussed above, see supra Part III.B.2.d, 
reducing the RBP Target by Qualifying RBP Offset UCAP MW guards against 
double-counting or procuring twice for the same capacity.  As such, the primary purpose 
of the RBP Target is to determine how much UCAP MW is needed to meet the reliability 
requirement shortfall without over-procuring. 
Recognizing that RBP Resources will have longer-term commitments and price 
certainty—as compared to resources that provide Qualifying RBP Offset UCAP MW, 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.  The RBP provides revenue 
certainty to encourage the development of new capacity in PJM, provided by new projects.  
Such revenue certainty demands a similar degree of certainty from the recipients of that 
revenue.  Accordingly, the generation, storage, demand, and DERs allowed to participate 
in RBP are a subset of those eligible to provide Qualifying RBP Offset UCAP MW.  
To put a finer point on the differences between Qualifying RBP Offset UCAP MW 
that may decrement the RBP Target and RBP UCAP MW that may be offered into the 
RBP, Ms. Croop describes several categories of resources that are eligible to serve as 
Qualifying RBP Offset UCAP MW, but are excluded from the categories of resources 
eligible to participate in the RBP.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 53 
 
 
 
First, as Ms. Croop testifies, a resource that increases UCAP by switching fuels and 
thus changes ELCC class, which can increase the resource’s accreditation value, is not 
eligible to be offered in the RBP.  According to Ms. Croop, “[f]uel switching does not bring 
new ICAP or new [maximum facility output] on to the system.”142  Further, anticipated 
UCAP increase resulting in the resource changing ELCC class is not driven by bringing 
new physical capacity to the system.  “[T]he potential new UCAP captured from this 
resource would require some estimate of the incremental UCAP value, which may require 
sensitivity analyses, to determine the delivered incremental UCAP and RBP payment, that 
cannot be based on any direct increase in ICAP for the resource.  This creates uncertainty 
in what capacity will be available to the system in the 15-year term and should be settled 
under the RBP.”143 
Second, as Ms. Croop testifies, CIR uprates that bring additional UCAP MW to the 
PJM system will not qualify to participate in the RBP, because CIR uprates bring neither 
new ICAP nor new energy to the system.144  Rather, to qualify, any incremental capacity 
created by new CIRs must also be associated with an increase in ICAP.145 
Third, resources relying on Surplus Interconnection Service to bring new UCAP 
MW on the PJM system do not qualify as RBP Resources, because these resources do not 
have any independent rights to the PJM system.  As Ms. Croop testifies:  
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 
 
142 Croop Aff. ¶ 19. 
143 Id. 
144 Id. ¶ 15. 
145 Id.; proposed Tariff, Attachment DD, section 18.2(b).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 54 
 
 
 
existing resource is not operating and using the 
interconnection service.  Given the 15-year term, resources 
need to be able to operate independently to provide certainty 
of deliverability for a 15-year term.  Further, these projects, 
while increasing UCAP in a hybrid configuration, do not 
have clear contributions of UCAP between the existing 
resource and surplus resource creating uncertainty and the 
need for sensitivities or estimates in both the increase system 
capacity and the RBP settlements.146 
Fourth, Demand Resources and DER Aggregators without identified sites and a 
15-year agreement in place will not be permitted to participate in the RBP.  These 
restrictions are necessary, according to Ms. Croop, “to provide assurance that the supply 
will be available for the 15-year term and manage the risk of the supply being available for 
the full term that PJM is procuring on behalf of load in the RBP.”147  By contrast, the 
commitment terms (length, price, etc.) of Qualifying RBP Offset UCAP MW are managed 
by the commercial contract between the buyer and seller. 
4. 
RBP Sell Offers (proposed Tariff, Attachment DD, section 18.5(e))  
Sellers participating in the RBP must submit RBP Sell Offers for RBP UCAP MW 
in $/MW-day UCAP for each Delivery Year, beginning with the first full Delivery Year in 
which the RBP UCAP MW is expected to achieve commercial operation and provide 
capacity, and through the end of the fixed 15-year term.  Each RBP Sell Offer must include:  
i) 
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 through the last posted Delivery Year or based on the 
resource’s maximum estimated unit-specific ELCC ratings across 
 
146 Croop Aff. ¶ 20. 
147 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 55 
 
 
 
such period for resources with no ELCC Class Rating, multiplied by 
the resource’s ICAP; 
ii) 
the price in $/MW-day UCAP for each Delivery Year beginning 
with the first full Delivery Year in which the RBP UCAP MW is 
expected to provide capacity through the end of the fixed 15-year 
term;         
iii) 
the first full Delivery Year for which such resource will be available; 
and 
iv) 
all relevant documentation necessary for the Office of the 
Interconnection to evaluate whether the project satisfies the gating 
criteria, as set forth in Tariff, Attachment DD, section 18.5(f)(i). 
PJM also proposes to cap the maximum amount of MW (UCAP) offered for any 
given resource at “120% of the resource type’s most recent maximum Preliminary ELCC 
Class Ratings for 2028/2029 through the last posted Delivery Year.”148  This cap reflects 
the fact that a resource’s Accredited UCAP value may change from year to year, based on 
the ELCC accreditation approach.  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.  In other words, if a seller believes that their resource’s current ELCC rating is 
understated relative to what the seller projects for future Delivery Years, the seller would 
be free to offer at a level greater than would be estimated today, while simultaneously 
incurring the risk that the resource’s final UCAP value for the Delivery Year comes in 
below the RBP offered value for such Delivery Year.  PJM’s proposed 120% cap level 
represents a reasonable balance between providing the seller with flexibility and managing 
UCAP risk for load.  Indeed, the 120% cap is comparable to Southwest Power Pool, Inc.’s 
recently proposed cap to High Impact Large Load Generation Assessment (“HILLGA”) 
 
148 Proposed Tariff, Attachment DD, section 18.5(e)(i).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 56 
 
 
 
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.149   
5. 
RBP Sellers Responsible for Actual Network Upgrade Costs 
(proposed Tariff, Attachment DD, section 18.5(e))  
Sellers of RBP Sell Offers will be responsible for all actual network upgrade costs 
as determined through the interconnection process, without any subsequent adjustments to 
RBP Sell Offers.  Sellers will have the opportunity to reflect on the anticipated cost of any 
network upgrades, estimated or final, associated with the RBP Resource’s provision of 
capacity in the RBP Sell Offer. 
6. 
Must-offer obligation in the RPM for RBP committed resources 
(proposed Tariff, Attachment DD, sections 18.6(a) and 18.6(b)) 
A committed RBP Resource must 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, 15-year term.150  The only exception to this general rule is that if an RBP 
Resource has a 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, 
 
149 Sw. Power Pool, Inc., 194 FERC ¶ 61,031 at P 66 (finding that Southwest Power Pool, Inc.’s “proposed 
cap on the projected capacity accreditation value helps to ensure that only the generation capacity necessary 
to serve the [High Impact Large Load (”HILL”)] is studied through the HILLGA process, while recognizing 
that the relevant load responsible entity must secure sufficient resources to cover the Planning Reserve 
Margin that it will be required to carry when the HILL receives long-term, firm transmission service”). 
150 Proposed Tariff, Attachment DD, section 18.6(a).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 57 
 
 
 
such RBP Resource would be required to be offered into the Second Incremental Auction 
for the 2029/2030 Delivery Year.151  This limited exception is necessary because, as further 
explained in the section detailing changes to the notice of intent requirement, 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.  
Requiring the portion of an RBP Resource that has committed RBP UCAP MW to 
be offered into the RPM Auctions as a price taker is appropriate given that such MW with 
an RBP commitment are already being paid for by the responsible LSEs so placing a 
must-offer requirement on RBP Resources and requiring such offers to be submitted as 
price takers during the term of such commitment ensures that load does not double pay for 
capacity.  That is, if the portion of the committed RBP UCAP MW is not obligated to offer 
into the RPM Auction as a price taker, there is a risk that such resource may not clear the 
RPM Auction and another resource would need to be committed as capacity in such 
auction.  Such an outcome would effectively result in over-procuring capacity since a 
committed RBP Resource is already retained for resource adequacy purposes while the 
RPM Auction procures additional capacity targeted at meeting the reliability requirement. 
Beyond the requirement for the committed RBP UCAP MW portion of an RBP 
Resource to be offered into the RPM Auction as a price taker, the rules related to exceptions 
of the RPM must-offer obligation must also be narrowed for RBP Resources.  Specifically, 
under the existing rules, an Existing Generation Capacity Resource may be eligible for an 
 
151 See id.  The First Incremental Auction for the 2029/2030 Delivery Year was canceled due to the 
compressed auction schedule so the Second Incremental Auction is the next auction following the BRA for 
the 2029/2030 Delivery Year.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 58 
 
 
 
exception to the RPM must-offer obligation if it “(i) is reasonably expected to be physically 
unable to participate in the relevant Delivery Year; [or] (ii) has a financially and physically 
firm commitment to an external sale of its capacity . . . .”152  It remains appropriate to allow 
any Existing Generation Capacity Resource, including a committed RBP Resource, to not 
be offered into the RPM Auction if it is physically unable to participate in the relevant 
Delivery Year (e.g., deactivation, long-term physical operational restrictions to the ICAP 
of the resource or under other major repair, regulatory proceedings specific to the resource 
that will result in the retirement of the resource, or unable to achieve full commercial 
operation prior to the relevant Delivery Year)153 because such a resource could not 
reasonably be relied upon for capacity during the Delivery Year so it should not be counted 
as capacity supply in the RPM Auction.  However, even if an RBP Resource is granted an 
exception to the RPM must-offer obligation, the RBP Resource will nevertheless still be 
subject to RBP shortfall charges, as described below.154   
In addition, the owner of a committed RBP Resource should not be allowed to 
circumvent the must-offer obligation simply by obtaining a financially and physically firm 
commitment to an external sale of capacity.  That is, a committed RBP Resource is 
procured to provide capacity for a 15-year term, and the resource is paid by the relevant 
LSEs within PJM.  Such committed RBP Resource should therefore be counted as capacity 
in the RPM Auctions and not be allowed to sell capacity outside of PJM and be exempt 
from the capacity market must-offer obligations. 
 
152 Tariff, Attachment DD, section 6.6(g). 
153 Id. 
154 Proposed Tariff, Attachment DD, section 18.6(b).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 59 
 
 
 
 
To prevent a committed RBP Resource from obtaining an exception to the 
must-offer obligation by selling the committed RBP UCAP MW of such resource outside 
of PJM, PJM proposes to add language to the Tariff that makes clear that the portion of 
any committed RBP UCAP MW of a Capacity Resource “shall not be eligible for an 
exception to the RPM must-offer requirement, under Tariff, Attachment DD, section 6.6A, 
based on having a financially and physically firm commitment to an external sale of its 
capacity.”155  Likewise, a committed RBP Resource should not be allowed to request 
removal of Capacity Resource status for the portion of the committed RBP UCAP MW 
during the commitment term as such a request could also effectively circumvent the 
capacity must-offer obligation.  To that end, PJM proposes to add a requirement to the 
Tariff that states that the Capacity Resource status of any committed RBP UCAP MW 
cannot be removed during the term of such commitment.156  However, if a resource has 
excess UCAP MW in addition to the committed RBP UCAP MW quantity, the excess 
UCAP MW may be eligible for a capacity must-offer exception.  Since the excess UCAP 
MW are not committed under the RBP, the RBP Resource may request that Capacity 
Resource status be removed for the excess UCAP MW under the existing rules, just like 
any other Existing Generation Capacity Resource.  
All RBP Resources that offer and clear in the RPM are paid RPM Auction Credits 
in accordance with longstanding RPM rules, and then will be settled based on the contract 
for difference (“CfD”) design for the RBP UCAP MWs.  All load that is allocated RBP 
 
155 Proposed Tariff, Attachment DD, section 6.6(g). 
156 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 60 
 
 
 
Charges and participates in the RPM will likewise be charged RPM Charges and be 
charged or receive RBP Charges, based on the CfD settlement. 
7. 
RBP UCAP MW shortfalls or failure to materialize (proposed Tariff, 
Attachment DD, sections 18.6(c) through 18.6(e)) 
PJM is proposing two mechanisms to manage the risk of RBP Resources not 
performing:  (1) an RBP UCAP MW shortfall charge, and (2) settlement on delivery.  An 
RBP UCAP MW shortfall occurs when a committed RBP Resources has not reached 
commercial operation for the relevant Delivery Year for up to three consecutive years 
during the term of the commitment.  Once an RBP Resource has achieved commercial 
operation, the RBP UCAP MW shortfall charge will no longer be assessed.  However, RBP 
Resources are not compensated for the amount of RBP UCAP MW that the resources are 
short of their RBP commitment. 
There is one exception.  Namely, as proposed, “[a]n 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.”157   
RBP shortfall charges will be equal to the committed RBP UCAP MW times a 
charge rate equal to 20% of the RBP commitment price of such resource (i.e., RBP shortfall 
charge = committed RBP UCAP MW * 20% of RBP commitment price) in the applicable 
Delivery Year.  RBP shortfall charges are assessed against an RBP Resource that fails to 
reach commercial operation and provide capacity for up to three consecutive Delivery 
 
157 Proposed Tariff, Attachment DD, section 18.6(d)(i).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 61 
 
 
 
Years.  If the RBP Resource fails to provide any RBP UCAP MW after three consecutive 
Delivery Years, the RBP commitment will be rescinded for the remainder of the RBP 
Resource’s fixed, 15-year term.  Once a commitment is rescinded, the RBP Resource will 
neither be eligible to receive compensation for the rescinded RBP UCAP MW nor be 
subject to an RBP shortfall charge for the remainder of the 15-year term.   
PJM is proposing to allow RBP Resources to retain RBP UCAP MW commitments 
for up to three years in recognition of the fact that a resource’s commercial operation date 
may be delayed, at times, even where a project is viable.  Shortfall charges assessed against 
RBP Resources will be allocated to load.  Should a project not reach commercial operation 
after the first three Delivery Years in which it was expected to be online, the resource 
would not be subject to additional RBP shortfall charges.  The limitation on RBP shortfall 
charges helps reduce the barrier to entry, as RBP shortfall charges over the entire 15-year 
commitment term, and the associated credit requirements for such an extended exposure to 
the RBP shortfall, could be significant. 
8. 
Clearing 
structure 
(proposed 
Tariff, 
Attachment 
DD, 
section 18.5(f))  
a. 
The MW-weighted average of the levelized procurement 
cost of all selected RBP Sell Offers shall not exceed 
$555/MW-day UCAP. 
PJM is proposing that the levelized procurement cost of all selected RBP Sell Offers 
not exceed a maximum willingness to pay of $555/MW-day UCAP, on a MW-weighted 
average basis over all Delivery Years of the RBP.158  Earlier this year, as part of the 
Commission’s order finding that PJM’s Periodic Review of certain inputs into the RPM 
 
158 Proposed Tariff, Attachment DD, section 18.5(f)(ii).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 62 
 
 
 
were just and reasonable, the Commission accepted an estimated, uncollared price cap of 
$555/MW-day (UCAP), which is Point 1 on the Variable Resource Requirement (“VRR”) 
curve for 2028/2029 Delivery Year BRA.159  In other words, but for the collared price cap, 
$555/MW-day (UCAP) would have been the cap for the 2028/2029 Delivery Year BRA.  
Given the RBP is starting with an Initial RBP Target of the 2028/2029 Delivery Year 
shortfall, $555/MW-day is being proposed as the maximum willingness to pay, i.e., a cap 
to what load will pay for RBP capacity.  This ‘budget approach’ selection design allows 
the procurement to manage cost to load over the fixed, 15-year term of the RBP, while not 
restricting Sell Offers to a hard price cap, and also allowing for potentially fluctuating 
offers throughout the Delivery Years of the term. 
b. 
The proposed maximum willingness is just and reasonable. 
A maximum willingness to pay set at the MW-weighted average of the levelized 
procurement cost not exceeding Point 1 on the VRR curve for the 2028/2029 Delivery Year 
BRA, i.e., $555/MW-day UCAP, is just and reasonable.  First, the proposed maximum 
willingness to pay weighs the need to procure capacity and maintain system reliability, 
recognizing that prices above the uncollared price cap based on Point 1 of the VRR curve 
for the 2028/2029 Delivery Year BRA may nevertheless be appropriate under scarcity 
conditions, while also weighing consumer protection considerations by requiring that, 
ultimately, the average procurement price not exceed the uncollared price cap of 
$555/MW-day UCAP across the term of the RBP commitment.160   
 
159 PJM Interconnection, L.L.C., 194 FERC ¶ 61,049 at PP 44-45, order addressing arguments raised on 
reh’g, 196 FERC ¶ 61,007 (2026).  
160 Croop Aff. ¶¶ 26-29.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 63 
 
 
 
Second, relying on a MW-weighted average of the levelized procurement cost 
provides sellers with flexibility not afforded by a hard cap on RBP Sell Offers.  The simple, 
illustrative example, below, demonstrates how price flexibility is permitted under this 
approach, without wholly setting aside the price discipline of a cap.  
Example: Final RBP Target = 1,000 MW 
Offers 
MW 
Levelized Offer 
Unit 1 
250 
$475 
Unit 2 
250 
$500 
Unit 3 
250 
$525 
Unit 4 
250 
$600 
 
• The MW-weighted average of the levelized procurement cost in this simplified 
example would be $525MW-day, i.e., less than the proposed MW-weighted 
average of the levelized procurement cost of all selected RBP Sell Offers not 
exceeding $555 MW-day.  All offers would be committed.   
• If instead, Offer 4’s levelized offer was priced at $800, Offer 4 would not be 
committed.  That is, if Offer 4’s offer was priced at $800, the levelized 
procurement cost would be $575 MW-day, which is greater than $555 MW-day. 
The proposal to limit the maximum willingness to pay is necessary.  The RBP is 
not disciplined by direct buy bids that explicitly express willingness to pay.  
Simultaneously, as Ms. Croop attests, “it is not reasonable to assume that load should be 
obligated to pay an unlimited amount for supply.  As with other PJM procurement 
mechanisms, an upper bound helps.”161  In comparison to the BRA 1-year commitment, 
the proposed RBP will be committing supply for an up to 15-year term.  This outcome 
 
161 Id. ¶ 26.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 64 
 
 
 
creates revenue certainty for the supply resources and generally can reduce financial and 
development risk and may improve financing opportunities through lower capital costs or 
more favorable financing terms.  Given these potential benefits, 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 for 
the targeted Delivery Year. 
The Commission has previously found that it is just and reasonable to pair a 
pay-as-bid approach to backstop procurement with a maximum willingness to pay.  In 
transitioning from administrative pricing to competitive, pay-as-bid pricing, California 
Independent System Operator Corporation (“CAISO”) paired the transition with a soft 
offer cap.  The Commission accepted CAISO’s proposed soft offer cap, reasoning that 
“because the soft offer cap represents the high end of the range of current resource 
adequacy prices, it should not create incentives for load-serving entities to forego bilateral 
resource adequacy contracts and, instead, rely on Capacity Procurement Mechanism 
(“CPM”) backstop procurement.”162  In the case of the RBP, the proposed maximum 
willingness to pay is based on the Commission-approved price cap set administratively 
through PJM’s periodic review, equal to Point 1 on the Commission-approved VRR curve, 
representing the high end of the range of uncollared clearing prices.  
 
162 Cal. Indep. Sys. Operator Corp., 153 FERC ¶ 61,001, at P 29 (2015).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 65 
 
 
 
c. 
The pay-as-bid approach is just and reasonable for purposes 
of the RBP  
PJM proposes to commit resources in the RBP using a pay-as-bid approach,163 
which is more appropriate for a one-time backstop procurement than the single-clear-price 
approach used in the RPM.  As Ms. Croop attests, the “RBP differs significantly from 
PJM’s standard market constructs and warrants a different settlement approach” and, while 
“PJM generally supports a single-clearing-price market design and continues to view 
uniform clearing prices as the most efficient market outcome,”164 given the unique 
circumstances of this procurement, the pay-as-bid structure is more appropriate. 
First, the RBP is a backstop procurement that has become necessary due to the 
unprecedented capacity shortfall in the PJM Region.  As a one-time procurement, Ms. 
Croop testifies, a uniform clearing price procurement, which “promotes transparent price 
discovery, facilitates forward pricing, and supports competitive market outcomes,”165 
would be ill-suited to the RBP.  As Ms. Croop states, the RBP “is not designed to be a 
durable or repeatable procurement,” and therefore “its pricing outcomes are less likely to 
serve as incentive market signals.”166   
Second, the RBP will not be procuring a uniform commodity.  As Ms. Croop 
testifies: 
Although the RBP will seek a fixed, 15-year period of time 
for procurement and cost allocation of RBP Resources, those 
resources may differ based on contract duration (dependent 
on the projected in-service date of selected resources), 
 
163 Proposed Tariff, Attachment DD, section 18.5(f). 
164 Croop Aff. ¶¶ 21, 22. 
165 Croop Aff. ¶ 21. 
166 Id. ¶ 23.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 66 
 
 
 
commercial operation dates, and other factors such as 
differences in ELCC accreditation and varying UCAP across 
the full term of the commitment.  These differences create 
distinct products rather than a single homogeneous 
offering.167 
Resource-specific network upgrade costs and commercial operation date risks differ from 
resource to resource.   
Third, without a “marginal unit” in any meaningful sense of the term, a single 
clearing price would transfer inframarginal rents to every seller priced below the most 
expensive accepted offer.  A uniform clearing price would, according to Ms. Croop, 
“require PJM to normalize offers through potentially complex and subjective assumptions.  
A pay-as-bid structure avoids those challenges while providing a straightforward and 
transparent procurement framework.”168  
d. 
No direct market power screens or mitigation  
No direct market power screens or mitigation are being proposed for the RBP.  The 
RBP design does, however, minimize the potential for exercise of market power.  In the 
context of a pay-as-bid structure with a maximum willingness to pay set at $555/MW-day 
UCAP, the effectiveness of direct market screens or mitigation is limited.   
First, a pay-as-bid structure, unlike a single-clearing price structure, relies on 
individual clearing prices rather than a single clearing price.  Thus, as Ms. Croop explains, 
there is an “inability for one resource to impact the clearing price of any other resource in 
a pay-as-bid structure.  This is in contrast to a uniform clearing price market where the 
 
167 Id. ¶ 25. 
168 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 67 
 
 
 
marginal resource will set the clearing price and all resources will receive that price.”169  
Ms. Croop’s affidavit provides the following concrete example: 
Seller has a fleet of three resources:  A, B, and C and offers accordingly: 
Resource A @$10/MW-day  
Resource B @$10/MW-day 
Resource C @$50/MW-day170 
Assuming that Resource C sets the market-clearing price at $50/MW-day in a 
single-clearing price structure, Resource A and Resource B would likewise receive the 
market-clearing price of $50/MW-day, and thus potentially collect inframarginal rents, i.e., 
economic gains realized where a resource’s costs fall below the market-clearing price.  In 
a single-clearing price auction, this is one of the key concerns that market mitigation 
measures are in place to address. 
In a pay-as-bid structure, however, Resource C’s offer price would not affect the 
prices of Resource A or Resource B.  Each resource committed would receive the price 
offered.  Resource C would only receive the $50/MW-day, and this offer would not 
influence the revenues for Resource A and B. 
Second, as discussed, above, PJM is proposing to pair the pay-as-bid structure with 
a maximum willingness to pay not to exceed $555/MW-day UCAP.  The existence of a 
reasonable maximum willingness to pay further discipline costs, where a resource raises 
its offer risks, that resource not clearing due to more economical offers and/or the costs 
exceeding the set maximum willingness to pay.   
 
169 Croop Aff. ¶ 34. 
170 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 68 
 
 
 
Third, in a pay-as-bid procurement in which suppliers voluntarily participate, as 
Ms. Croop explains, “the traditional incentive and ability to exercise market power are 
substantially reduced” where “each selected resource is compensated based on its 
individual offer rather than a market-clearing price established by the marginal 
resource.”171  Indeed, the risk of economic withholding is limited here, because “the 
procurement is voluntary, meaning suppliers can simply choose to participate or not, and 
then further PJM is proposing a maximum willingness-to-pay cap, which provides a direct 
limit on procurement costs even in the absence of offer mitigation.”172  PJM’s maximum 
procurement target under the RBP is limited to the 2028/2029 BRA shortfall of 
6,831.3 MW UCAP.  The RFI, administered by CRA, identified over 100 GW of 
prospective supply interested in participating in some form through this process.173  This 
level of interest indicates there is available supply that will compete to secure an RBP 
commitment.  PJM 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.  As a result, there is sufficient prospective supply to satisfy the 
identified 2028/2029 reliability need.  This expanded supply eligibility mitigates scarcity 
conditions that would otherwise exist for the 2028/2029 Delivery Year and indicating the 
ability to create meaningful competition among suppliers seeking RBP contracts.  In 
scarcity conditions, suppliers may have incentives to submit offers at or near the applicable 
maximum willingness to pay.  However, due to the abundance of eligible supply competing 
 
171Id. ¶ 32. 
172 Id. ¶ 34. 
173 Charles River Associates Presentation at 5.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 69 
 
 
 
for the limited RBP contracts, competitive dynamics are expected to encourage suppliers 
to submit competitive offers that more closely reflect their willingness to provide service. 
Under a pay-as-bid structure, such competition should exert downward pressure on 
procurement costs and improve the efficiency of the RBP procurement process.174 
Fourth, the Commission, under somewhat similar circumstances, has previously 
found the pay-as-bid approach to be just and reasonable.  The Commission also previously 
found that, with respect to the CAISO’s CPM, CAISO’s proposal to transition from an 
administratively set, single-clearing price to a pay-as-bid approach, was just and 
reasonable.175  The CPM, like the RBP in PJM, is a “voluntary backstop mechanism that 
authorizes CAISO to procure capacity to address a deficiency or supplement resource 
adequacy procurement by load-serving entities, as needed, to maintain grid reliability.”176  
In 2015, the Commission accepted CAISO’s proposal “to implement a competitive 
solicitation process and pay designated resources their bid price, rather than paying an 
administratively set price, subject to a soft offer cap.”177  In doing so, the Commission held 
that, as to the CPM, the “the pay-as-bid approach is appropriate because it is a backstop 
procurement mechanism” that is intended “to respond to unexpected reliability needs.”178  
Furthermore, as CAISO explained, “a pay-as-bid approach, rather than a single clearing 
 
174 Croop Aff. ¶¶ 35 (citing Charles River Associates Presentation), 36. 
175 Cal. Indep. Sys. Operator Corp., 153 FERC ¶ 61,001. 
176 Id. at P 2. 
177 Id. at P 8. 
178 Id. at P 28.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 70 
 
 
 
price, reflects the unique nature of the CPM, which is designed as a rarely used backstop 
procurement mechanism to address short-term transitory events.”179 
Fifth, unlike CAISO’s CPM,180 the RBP is intended to incentivize and procure new 
capacity resources rather than existing resources with established costs.  In this respect, the 
proposed cap for the RBP is similar to the existing market mitigation rules for Planned 
Generation Capacity Resources.  As set forth in the Tariff provisions on mitigation for 
Planned Generation Capacity Resources,  
Sell Offers based on Planned Generation Capacity Resources . . . 
shall be presumed to be competitive and shall not be subject to 
market power mitigation in any Base Residual Auction or 
Incremental Auction for which such resource qualifies as a Planned 
Generation Capacity Resource, but any such Sell Offer shall be 
rejected if it meets the criteria set forth in subsection (C) 
below . . . .181 
 
In subsection (C) of the Tariff provision, Sell Offers of Planned Generation capacity 
Resources may be rejected if it exceeds 140% of an average, relevant price.182  In other 
 
179 Id. at P 15; see also Cal. Indep. Sys. Operator Corp., Tariff Amendment and Offer of Settlement Regarding 
Capacity Procurement Mechanism Revisions and Request for Waiver of Notice Requirement of California 
Independent System Operator Corporation, Docket No. ER15-1783-000, Transmittal at 15 (May 26, 2015) 
(stating “compensation on a pay-as-bid approach, rather than a single clearing price, reflects the unique nature 
of the CPM and the CPM competitive solicitation process.  CPM serves as a rarely used backstop 
procurement mechanism to address short-term transitory events.  The CAISO typically relies on CPM to 
procure an individual resource to respond to unexpected, unplanned-for system conditions or meet unique 
reliability needs that might occur at a given point in time.  CPM is not a capacity clearing market like those 
in place in the eastern ISOs and RTOs, and it is not a process for clearing load and supply in the marketplace.  
Backstop capacity generally is non-homogenous (limited interchangeability) because the CAISO typically 
designates CPM capacity based on specific characteristics such as location or resource capabilities” (footnote 
omitted)). 
180 See Cal. Indep. Sys. Operator Corp., CAISO Tariff Amendment and Offer of Settlement Regarding 
Capacity Procurement Mechanism Revisions and Request for Waiver of Notice Requirement, Docket No. 
ER15-1783-000, Transmittal at 15 (May 26, 2015) (“[T]he CPM backstop is not intended to incentivize new 
generation.”). 
181 Tariff, Attachment DD, section 6.5(a)(ii)(A). 
182 Tariff, Attachment DD, section 6.5(a)(ii)(C) (Sell Offers of Planned Generation Capacity Resources may 
be rejected if it exceeds 140% of an average price established around the VRR Curve if “the average of 
location-adjusted Sell Offers for Planned Generation Capacity Resources from the same asset class,” “if there

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 71 
 
 
 
words, the existing offer cap for Planned Generation Capacity Resources is based on an 
average of offers from all Planned Generation Capacity Resources.  Similarly, for new 
capacity resources in the RBP, the proposed cap, based on a MW-weighted average of the 
levelized procurement cost of all selected RBP Sell Offers not exceeding $555/MW-day 
UCAP, provides a zone of reasonable prices, much like the volume-weighted average 
applied to Planned Generation Capacity Resources as a mitigation measure.183 
Notwithstanding the above, the implementation of market mitigation measures in a 
pay-as-bid construct can be difficult to verify and ineffective.  As Ms. Croop explains, “[i]n 
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.  Given 
offers will likely have less variation and information underlying offers it can be difficult 
and ineffective to determine offers exhorting market power.”184 
e. 
Stage 1:  gating criteria—ensuring the viability of the 
resource to be developed (proposed Tariff, Attachment DD, 
section 18.5(f)(i)) 
To ensure that resources selected through the RBP are those most likely to go into 
service and provide needed capacity and to deter offers of speculative resources, PJM is 
proposing “gating” criteria under which the seller will provide certain evidence designed 
to demonstrate that the proposed resource will be successfully completed and able to 
provide capacity.  As detailed below, the required information should demonstrate that the 
 
is no Asset-Class New Plant Offers for such Delivery Year, the average Asset-Class New Plant Offers for all 
prior Delivery Years” or “if there are no Asset-Class New Plant Offers for any prior Delivery Year, the net 
[Cost of New Entry] applicable for such Delivery Year in the [locational deliverability area] for which such 
Sell Offer was submitted.”) 
183 See Tariff, Attachment DD, section 6.5(a)(ii). 
184 Croop Aff. ¶ 33.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
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resource is likely to be fully developed and the seller has taken all necessary steps (at this 
stage) to succeed. 
RBP Sell Offers must include the applicable information in order to be considered 
valid and advance to the price evaluation stage.185  PJM is proposing different evidence 
demonstrating likelihood of successful development for generation/storage resource 
developers than from demand resource developers, with each set of requirements tailored 
to the specific characteristics of the resource types.  However, given the importance of such 
information, before failing to advance an offer to the price evaluation stage, PJM will 
provide sellers the opportunity to cure any PJM-identified deficiencies.  Sellers will have 
five calendar days, or up to the close of the bid submission window, to cure.186   
For RBP Sell Offers of generation and storage resources, the seller must provide 
various types of evidence demonstrating that the project is at a substantially advanced stage 
of development and therefore showing that it is not speculative and is likely to provide 
capacity corresponding to its commitment.  Specifically, the seller must provide the 
following evidence:   
• Critical path construction schedule (with seller attestation) supporting the 
feasibility of commercial operation date of June 1, 2032, or earlier;187  
• Applicable interconnection study information and development timeline 
appropriate to its interconnection queue study process;188  
 
185 See proposed Tariff, Attachment DD, section 18.5(f)(i). 
186 See id. 
187 See proposed Tariff, Attachment DD, section 18.5(f)(i)(1) (“A critical path construction schedule and 
expected commercial operation date, with attestation, for the Office of the Interconnection to validate that 
RBP Sell Offers are for RBP UCAP MW with a feasible commercial operation date of June 1, 2032 or 
earlier.”). 
188 See proposed Tariff, Attachment DD, section 18.5(f)(i)(1)(A) (“With respect to a project in Transition 
Cycle #2 under Tariff, Part VII and earlier, such project must provide study information and timeline from

Honorable Debbie-Anne A. Reese 
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Page 73 
 
 
 
• Evidence of 100% site control;189 
• Financing plan, showing that the resource has sufficient financial backing 
to be successfully completed;190 
• Permitting plan, showing that the developer is on track to obtain all 
necessary and applicable permits to complete the project;191 and 
• Signed memorandum or other documentary evidence that the developer has 
or will procure the major equipment necessary to develop the resource.192 
In addition, the seller must demonstrate that it is able to actually 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.”193  A seller offering RBP UCAP MW based on 
a natural gas-fired resource must provide evidence that there will be a pipeline delivering 
 
its most current PJM study.”); see proposed Tariff, Attachment DD, section 18.5(f)(i)(1)(B) (“With respect 
to a project in Cycle 1 under Tariff Part VIII, the Expedited Interconnection Track under Tariff, Part X, or 
not under study, the project must provide study information and timeline from an independent consultant 
report.”). 
189 See proposed Tariff, Attachment DD, section 18.5(f)(i)(2) (“Evidence of 100% Site Control for each of 
the Generating Facility (including the location of the main step-up transformer), the Interconnection 
Facilities, and the Interconnection Switchyard (as defined in the PJM Manuals) for a term of at least three 
years from the date of submission of the Application.  In addition, a certification, executed by an officer or 
authorized representative of the Generation Project Developer, verifying that the Site Control requirements 
have been met. Further, at Transmission Provider’s request, Generation Project Developer shall provide 
copies of landowner attestations or county recordings.  The Site Control requirements include an acreage 
requirement for the Project, as set forth in the PJM Manuals.  Evidence of site control consistent with Tariff, 
Part VIII, Subpart A, section 402.”). 
190 See proposed Tariff, Attachment DD, section 18.5(f)(i)(3) (“Financing plan, i.e., identified financing 
sources and details (e.g., project financing, balance sheets, tax equity, sponsor equity), current status of any 
financing commitments or term sheets, and a general description of the capital structure and expected timeline 
to financial close.”). 
191 See proposed Tariff, Attachment DD, section 18.5(f)(i)(4) (“Permitting plan, e.g., a list of all applicable 
permits, current status, and timeline to obtain each.”). 
192 See proposed Tariff, Attachment DD, section 18.5(f)(i)(5) (“Signed memorandum for the acquisition of 
major equipment, invoices or agreements to acquire major equipment, or other documentary evidence that 
major equipment has been procured.”). 
193 Proposed Tariff, Attachment DD, section 18.5(f)(i)(6).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 74 
 
 
 
the natural gas to the resource.194  And, finally, to the extent the resource is located outside 
the PJM Region, the seller must demonstrate that the resource has sufficiently progressed 
through its host region’s interconnection study process to have obtained “a completed 
facilities study or [the] equivalent” and, consistent with PJM’s pseudo-tie requirements for 
external Capacity Resources in Tariff, Attachment DD, section 5.5A(b), 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 the border of the PJM 
Region.”195 
For RBP Sell Offers of Annual Demand Resources and DER Capacity Aggregation 
Resources, the seller must provide certain evidence demonstrating that the resource will be 
capable of providing the offered load reduction over the term of the agreement.  To this 
end, PJM is proposing that such RBP Sell Offers must be accompanied by the following 
evidence supporting the offered load reduction:  
• The locations within PJM of the load reduction;196 and 
• Executed customer agreements or binding commitments with identified 
locations and customer names sufficient to cover the offered MW 
quantity.197  
 
194 See proposed Tariff, Attachment DD, section 18.5(f)(i)(7) (“For natural gas-fueled generation resources, 
evidence of delivery infrastructure arrangements in the form of a notice of intent or attestation of pipeline 
capacity expansion to support the new project.”). 
195 Proposed Tariff, Attachment DD, section 18.5(f)(i)(8). 
196 See proposed Tariff, Attachment DD, section 18.5(f)(i)(9) (“Locations within the PJM Region by 
Zone/Sub-zonal [locational deliverability area] and aggregate capacity for RBP Sell Offers.”). 
197 See proposed Tariff, Attachment DD, section 18.5(f)(i)(10) (“Executed customer agreements or binding 
commitments covering the proposed RBP UCAP MW commitment, with identified locations, customer 
names, and expected curtailment/injection capability per site.”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 75 
 
 
 
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.”198 Finally, the 
seller must demonstrate that it has coordinated with the Electric Distributor to ensure the 
resource will meet applicable requirements.199 
f. 
Stage 2:  selection assessment 
After PJM has evaluated an RBP Sell Offer’s “gating” criteria evidence 
demonstrating that the underlying resource has a high likelihood of successfully delivering 
the offered capacity over the 15-year timeframe, PJM will then evaluate the RBP Sell 
Offers “based on the first Delivery Year offered in the RBP Sell Offer, levelized cost, and 
RBP UCAP MW quantity.200  The selection process will first order all Sell Offers based 
on the 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.”201  From this stack of offers, PJM will select RBP Sell Offers “until 
the Final RBP Target is satisfied.”202   
 
198 See proposed Tariff, Attachment DD, section 18.5(f)(i)(11) (“Equipment 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.”). 
199 See proposed Tariff, Attachment DD, section 18.5(f)(i)(12) (For DER Capacity Aggregation Resources, 
“[a]pplicable Electric Distributor interconnection/distribution impact study requirements and a plan to initiate 
on a timeline consistent with the proposed delivery date.”); see proposed Tariff, Attachment DD, section 
18.5(f)(i)(13) (For Demand Resources, “Electric Distributor coordination requirements for metering, 
telemetry, and baseline measurement infrastructure.”). 
200 Proposed Tariff, Attachment DD, section 18.5(f)(ii). 
201 Id. 
202 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 76 
 
 
 
The affidavit of Ms. Croop includes three examples, appended as Exhibit 1 to her 
affidavit, which provide step-by-step explanations of how RBP Sell Offers are assessed 
and selected by Delivery Year and price of each RBP Resource, as identified in terms of 
levelized procurement cost and levelized MW value across the fixed, 15-year term.203  The 
first example describes how one resource’s offer price and MW quantity are levelized 
across the term.204  The second and third examples demonstrate how a set of offers are 
evaluated based on ranked Delivery Year and levelized cost, and provide descriptions of 
each step in the selection process.205 
As explained above, see supra Part I.A, all RBP commitments terminate with the 
2042/2043 Delivery Year, regardless of which Delivery Year the RBP Resource first 
offered.  Therefore, 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.   
Thus, it is necessary to calculate a levelized procurement cost for each RBP Sell 
Offer.  As Ms. Croop explains, “levelized cost of capacity is an industry standard 
evaluation metric used in competitive resource procurements across the country.  The 
levelized cost calculation for evaluation addresses the fundamental issue of a simple MW-
weighted average cost by accounting for the time value of money, which is critical when 
evaluating contracts spanning 15-year terms, as PJM is proposing in the RBP.  Levelizing 
 
203 Croop Aff., Exhibit (“Exh.”) 1 (Examples Demonstrating RBP Resource Procurement Process).  
204 Id. at 1-2. 
205 Id. at 2-7.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 77 
 
 
 
properly discounts future cost streams to a common basis, giving us a true economic 
comparison across bids.”206 
This period will be considered in the determination of the levelized cost of each 
RBP Sell Offer shall 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 (‘ATWACC’).”207  
The 9.5% ATWACC is appropriate here, as Ms. Croop attests, as the proposed discount rate 
was The Brattle Group-estimated calculated value used in the 2025 Periodic Review of 
Variable Resource Requirement Curve Shape and Key Parameters.208 
PJM has designed the RBP clearing mechanism to recognize the 15-year timeframe 
and that there may be issues with all offered resources having a reasonably expected 
commercial operation date by June 1, 2028.  First, the Final RBP Target is fixed and is the 
target value for each year of the 15-year period.  Second, in selecting resources from the 
offer stack, PJM will first try to satisfy the Final RBP Target with RBP Resources expected 
to reach commercial operation in the 2028/2029 Delivery Year.  If the set of resources 
offered with expected commercial operation dates in the 2028/2029 Delivery Year 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.  PJM will continue to apply the selection criteria iteratively, up to and 
 
206 Croop Aff. ¶ 30. 
207 Id. ¶ 31. 
208 Id. (citing 2025 Periodic Review of Variable Resource Requirement Curve Shape and Key Parameters, 
PJM 
Interconnection, 
L.L.C. 
(Nov. 
7, 
2025), 
https://www.pjm.com/pjmfiles/directory/etariff/FercDockets/9248/20251107-er25-455-000.pdf 
[https://perma.cc/87GP-AYL5]).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 78 
 
 
 
including the 2032/2033 Delivery Year, until the set of offers selected meets the Final RBP 
Target.   
Within this selection process PJM will continue to maintain the maximum 
willingness to pay and will not procure a resource that results in the MW-weighted average 
of the levelized procurement cost exceeding $555/MW-day.  As a result of this constraint, 
in the selection process, PJM may skip over a resource with an earlier Delivery Year if 
procuring that resource would violate the maximum willingness to pay for the procurement.   
Additionally, the selection is prioritizing earlier Delivery Years to address the 
shortfall target as soon as possible.  As a result, if a resource is skipped in the selection 
process because it violates the maximum willingness to pay 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’s proposed procurement process also provides for flexibility to select a more 
economically efficient solution.  In procuring the least-cost set of resources, PJM 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.209  For example, in the course 
of clearing, assume the Final RBP Target were 6,000 MW.  In this example, an RBP 
Resource would put the final RBP procurement at 6,001 MW (i.e., above the Final RBP 
Target) but remain within the maximum willingness to pay of $555/MW-day.  However, 
 
209 Proposed Tariff, Attachment DD, section 18.5(f)(ii) (“In selecting the least-cost solution that satisfies the 
Final RBP Target and the cost of procurement constraint, [PJM] may commit an RBP Sell Offer with an 
offered quantity that exceeds the remaining Final RBP Target to the extent such solution provides greater 
economic efficiency than an alternative solution that satisfies the requirements and constraints.”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 79 
 
 
 
higher priced offers for MW quantities within the 6,000 MW target exceed the $555/MW-
day maximum willingness to pay.  In this case, PJM may exercise the option to clear 6,001 
MW in the RBP, i.e., 1 MW above the procurement target, to maintain a total weighted 
average price at or below $555/MW-day.  Even though, in this example, PJM procured 
above the target, the overall cost was lower.  In this way, PJM chooses among alternative 
solutions and selects the more economically efficient outcome. 
Because the RBP is procuring new capacity and not simply fungible UCAP MW, 
PJM is proposing that “RBP Resources shall not be partially cleared.”210  Thus, there exists 
the possibility that PJM may clear a set of resources with a cumulative RBP UCAP MW 
total that does not exactly match the Final RBP Target.  PJM proposes that “[i]n the event 
that the Reliability Backstop Procurement cannot meet the Final RBP Target, the 
Reliability Backstop Procurement shall clear short of the Final RBP Target.”211   
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 MWs that were procured through the RBP and a weighted 
average of the RBP Charges as soon as practicable after the RBP is completed. 
9. 
Contract for difference settlement structure (proposed Tariff, 
Attachment DD, section 18.5(g)) 
 
Each committed RBP Resource will individually settle as a CfD.  The CfD 
settlement structure turns on a committed RBP Resource’s “strike price”—i.e., the RBP 
Sell Offer price at which the RBP Resource’s RBP UCAP MW is committed, expressed as 
 
210 Id. 
211 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 80 
 
 
 
$/MW-day UCAP.  Because the RBP is pay-as-bid, each committed RBP Resource has an 
individualized “strike price.”     
A committed RBP Resource must offer all committed RBP UCAP MW as a price 
taker in the RPM, unless the resource qualifies for an exception under the rules governing 
a committed RBP Resource participating in the RPM.  The “market price” is the RBP 
Resource’s unit-specific weighted average resource clearing price (“WARCP”) of all RPM 
Auctions in which the RBP Resource participated for the relevant Delivery Year, expressed 
as $/MW-day UCAP.212   
If the strike price of the total MW eligible to settle as a CfD is higher than the 
market price, the buyer (load) must pay the difference between the strike price and market 
price.  Alternatively, if the strike price of the total MW eligible to settle as a CfD is lower 
than the market price the seller (RBP Resource) must pay back the difference between the 
strike price and market price.   
The proposed CfD settlement structure is just and reasonable.  First, the CfD 
structure protects load from paying RBP Resources a windfall, while also protecting RBP 
Resources from settling below market prices.  Thus, the CfD structure provides stability 
during the lengthy term of an RBP Resource commitment and limits the potential risk of 
long-term exposure.   
Second, the CfD structure operates on the principle that payments for providing 
RBP UCAP MW should net out the market revenues from the RPM.  In other words, CfD 
 
212 Proposed Tariff, Attachment DD, section 18.5(g)(ii).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 81 
 
 
 
limits payment for RBP UCAP MW to the “missing money” and avoids double payment 
for the same capacity—once through the RPM and again through the RBP.  
Third, recognizing that the RBP locks in a fixed price for a fixed, 15-year term, the 
CfD structure is intentionally “self-correcting.”  Loads will fund the actual revenue 
shortfall, measured ex post, as opposed to an administrative guess about what that revenue 
shortfall might be.   
Fourth, the proposed CfD is not purely financial.  The total MW eligible to settle 
as a CfD will be:  (a) the lesser of the RBP Resource’s daily committed RBP UCAP MW, 
daily owned UCAP MW; and (b) daily cleared RPM UCAP MW.213  A physical availability 
requirement supports reliability, resource adequacy, market participation, and stable 
capacity revenue streams for RBP Resources.214  Under the proposed CfD settlement 
structure, RBP Credits and Charges will only be assessed to the extent that RBP UCAP 
MW are committed in the RPM and physically available for dispatch in the relevant 
Delivery Year.  To the extent that an RBP Resource fails to deliver the full RBP UCAP 
MW committed in the RBP, the RBP Settlement Credits, settled as a CfD, will only credit 
the lower of the daily committed RBP UCAP MW, daily owned UCAP MW, and daily 
cleared RPM UCAP MW.215   
 
213 Proposed Tariff, Attachment DD, section 18.5(g)(i). 
214 Croop Aff. ¶ 39. 
215 Proposed Tariff, Attachment DD, section 18.5(g)(i).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 82 
 
 
 
a. 
RBP Settlement Credits and RBP Charges 
RBP Resources that clear in the RBP are assessed RBP Settlement Credits, a daily 
value measured in $/day UCAP,216 which may be positive (indicating a payment to supply) 
or negative (indicating a reduction in payment to supply).   
Load allocated responsibility for RBP UCAP MW will be allocated RBP Charges, 
a daily value measured in $/day UCAP, which may likewise be positive (a reduction in 
cost to load) or negative (a cost to load).217   
For example, in a settlement where an RBP Resource is assigned a positive 
$10,000/Day RBP Settlement Credit, load is assigned a corresponding negative $10,000 
RBP Charge.   
Likewise, in accordance with the rules in place today, all RBP UCAP MW that 
offer and clear in the RPM will be assessed RPM Auction Credits, while load will be 
assessed RPM Charges. 
b. 
Examples of RBP Resource Settlements  
Tables 2-4, below, are illustrative examples of how a hypothetical RBP Resource 
that clears in both the RPM and the RBP is credited when the RBP price is higher, lower, 
or equal to the RPM price.  In Table 2, the same quantity of MW clear in the RPM and 
RBP.  In Table 3, more MW clear in the RPM than in the RBP, and in Table 4, fewer MW 
clear in the RPM than in the RBP.  The number of MW that clear in the RPM and RBP are 
 
216 Proposed Tariff, Definitions – RBP Settlement Credits (‘“RBP Settlement Credits’ shall mean, for each 
day in the Delivery Year in the term of the Reliability Backstop Procurement commitment period, the $/day 
value that a resource committed in the Reliability Backstop Procurement receives as a contract for differences 
settlement in accordance with Tariff, Attachment DD, section 18.5(g).”). 
217 Proposed Tariff, Definitions – RBP Charges (‘“RBP Charges’ shall mean the $/day value of the total RBP 
Settlement Credits, positive or negative, of all RBP Resources across the PJM Region.”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 83 
 
 
 
relevant because, as previously noted, the total MW eligible to settle as a CfD is limited to 
the lesser of the RBP Resource’s committed RBP UCAP MW for a Delivery Year, daily 
owned UCAP MW, and daily committed RPM UCAP MW.  Thus, for example, even if 
the resource committed more MW in the RPM than in the RBP, the CfD would still only 
be for the lower quantity of MW that committed in the RBP. 
Table 2 shows the outcomes of a hypothetical RBP Resource where the quantities 
of UCAP MW cleared in the RPM and RBP are equal (50 MW (UCAP)).  Table 3 shows 
the outcomes where a hypothetical RBP Resource clears more capacity in the RBP (50 
MW (UCAP)) than in the RPM (20 MW (UCAP)).  Table 4 shows outcomes where a 
hypothetical RBP Resource clears less capacity (20 MW (UCAP)) in the RBP than in the 
RPM (50 MW (UCAP)).  In each table, the “Total Credits” column is the total amount paid 
to the RBP Resource.  Tables 2-4 represent Resource Settlement.  Load Settlement is an 
inverse of the RBP Credits, i.e., where Resource Credits are paid to a resource, RBP 
Charges are assessed to load to cover the RBP Credits.  Together, Tables 2-4 provide 
concrete examples of how the CfD settlement structure supports long-term stability and 
price-certainty, while also providing a two-sided hedge that blunts potential gains from 
speculative offers in a pay-as-bid framework.   
As demonstrated in the first row of Table 2, where an RBP Resource clears 50 MW 
(UCAP) in both the RBP and RPM, and the RBP price is higher than the RPM price, at 
settlement, only the incremental value of the RBP Credits will be counted toward the total 
credits.  In other words, the 50 MW (UCAP) cleared in the RPM and RBP will not be paid 
twice for the same capacity.  The 50 MW (UCAP) will be paid the value of the RPM

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 84 
 
 
 
Auction Credits plus the RBP Settlement Credits, which is based on the difference between 
the RBP and RPM prices.   
However, CfD also serves a limiting role.  For example, in the second row of 
Table 2, the RBP price falls below the RPM price.  The RBP Settlement Credits now 
represent an incremental decrease in value of the capacity.  Thus, the RBP Resource is 
ultimately paid its expected RBP Credits. 
Table 2. Resource Settlement ($/day)  
Where UCAP MW Cleared in RBP and RPM Are Equal 
(RPM Cleared MW = 50 MW (UCAP), RBP Cleared MW = 50 MW (UCAP)) 
 
 
 
 
 
 
RBP and RPM Prices 
Expected 
RBP 
Credits 
RPM Auction 
Credits  
 
RBP 
Settlement 
Credits  
Total 
Credits 
RBP 
Cleared 
MW * RBP 
Price 
RPM Cleared 
MW * RPM 
Price+ 
RBP Cleared 
MW * (RBP 
Price – RPM 
Price+) 
RPM 
Auction 
Credits + 
RBP 
Settlement 
Credits 
RBP Price >  RPM Price+  
RBP Price =$250   
RPM Price+ = $200 
50 MW * 
$250 = 
$12,500 
50 MW * $200 
= $10,000 
50 MW * 
($250-$200) = 
$2,500 
$12,500 
RBP Price < RPM Price+  
RBP Price =$200   
RPM Price+ = $250 
50 MW * 
$200 = 
$10,000 
50 MW * $250 
= $12,500 
50 MW * 
($200-$250) =-
$2,500 
$10,000 
RBP Price = RPM Price+ 
RBP Price =$250   
RPM Price+ = $250 
 
50 MW * 
$250 = 
$12,500 
50 MW * $250 
= $12,500 
50 MW * 
($250-$250) = 
$0 
$12,500 
+Or, in the event resource clears in multiple RPM Auctions, RPM WARCP) 
In Table 3, the resource clears fewer MW (UCAP) in the RBP compared to the 
RPM.  As the first row of Table 3 illustrates, where the RBP price is higher than the RPM 
price, the resource receives the value of the RPM Auction Credits for all 50 MW in which 
the resource clears in the RPM and the CfD for only the 20 MW that clears the RBP.  In 
row two, where the clearing price of the RBP was lower than the RPM price, the CfD 
reduces the total amount credited to the RBP Resource based on the 20 MW that clears the

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 85 
 
 
 
RBP.  Finally, in row three of Table 3, where the clearing price for the RPM and RBP are 
the same and the MW UCAP that clears the RBP is lower than the RPM, the CfD does not 
change the total amount credited to the RBP Resource.         
Table 3. Resource Settlement ($/day)  
Where RBP Cleared MW < RPM Cleared MW  
RPM Cleared MW = 50 MW (UCAP), RBP Cleared MW = 20 MW (UCAP)  
 
 
 
 
 
 
RBP and RPM Prices 
Expected 
RBP 
Credits 
RPM 
Auction 
Credits  
 
RBP 
Settlement 
Credits  
Total 
Credits 
RBP 
Cleared 
MW * RBP 
Price 
RPM Cleared 
MW * RPM 
Price+ 
Lesser of 
Cleared MW * 
(RBP Price – 
RPM Price+) 
RPM 
Auction 
Credits + 
RBP 
Settlement 
Credits 
RBP Price >  RPM Price+  
RBP Price =$250   
RPM Price+ = $200 
20 MW * 
$250 = 
$5,000 
50 MW * $200 
= $10,000 
20 MW * 
($250-$200) = 
$1,000 
$11,000 
RBP Price < RPM Price+  
RBP Price =$200   
RPM Price+ = $250 
20 MW * 
$200 = 
$4,000 
50 MW * $250 
= $12,500 
20 MW * 
($200-250) = 
-$1,000 
$11,500 
RBP Price = RPM Price+ 
RBP Price =$250   
RPM Price+ = $250 
 
20 MW * 
$250 = 
$5,000 
50 MW * $250 
= $12,500 
20 MW * 
($250-$250) = 
$0 
$12,500 
+Or, in the event resource clears in multiple RPM Auctions, RPM WARCP) 
 
Table 4 demonstrates how resources settle when a resource clears more MW 
(UCAP) in the RBP compared to the RPM.  Again, the CfD at which the RBP settles will 
be the lower of the resource’s cleared MW in the RPM and the RBP.  Thus, even though 
the expected RBP Credits are based on 50 MW, the CfD at which the RBP settles is based 
only on the 20 MW that clears both the RBP and the RPM.  In row 1 of Table 4, the RBP 
price is higher than the RPM.  Only 20 MW clears in the RPM and, thus, the CfD settlement 
reflects only 20 MW.  While the expected RBP Credits was $12,500, the RBP Resource 
only receives $1,000 in the CfD settlement, plus the RPM Auction Credits of $4,000.  In 
row 2 of Table 4, the RBP price is lower than the RPM.  Thus, the CfD results in a reduction

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 86 
 
 
 
of the total amount credited to the RBP Resource.  Finally, in row 3 of Table 4, where the 
RBP and RPM prices are the same, the CfD does not add or subtract from the RPM Auction 
Credits.   
Table 4. Resource Settlement ($/day)  
Where RBP Cleared MW > RPM Cleared MW  
RPM Cleared MW = 20 MW (UCAP), RBP Cleared MW = 50 MW (UCAP) 
 
 
 
 
 
 
RBP and RPM Prices 
Expected 
RBP 
Credits 
RPM 
Auction 
Credits  
 
RBP 
Settlement 
Credits  
Total 
Credits 
RBP 
Cleared 
MW * RBP 
Price 
RPM Cleared 
MW * RPM 
Price+ 
Lesser of 
Cleared MW * 
(RBP Price – 
RPM Price+) 
RPM 
Auction 
Credits + 
RBP 
Settlement 
Credits 
RBP Price >  RPM Price+  
RBP Price =$250   
RPM Price+ = $200 
50 * $250 = 
$12,500 
20 MW * $200 
= $4,000 
20 MW * 
($250-$200) = 
$1,000 
$5,000 
RBP Price < RPM Price+  
RBP Price =$200   
RPM Price+ = $250 
50 MW * 
$200 = 
$10,000 
20 MW * $250 
= $5,000  
20 MW * 
($200-250) = 
-$1,000 
$4,000 
RBP Price = RPM Price+ 
RBP Price =$250   
RPM Price+ = $250 
 
50 MW * 
$250 = 
$12,500 
20 MW * $250 
= $5,000 
20 MW * 
($250-$250) = 
$0 
$5,000 
+Or, in the event resource clears in multiple RPM Auctions, RPM WARCP) 
c. 
Settlement of RBP Resources with MW Shortfalls, RBP 
shortfall charges, RPM Commitment Deficiency MW, and 
RPM 
Commitment 
Charges 
(proposed 
Tariff, 
Attachment DD, section 18.6(d)) 
As noted above, see supra Part III.C.9, the total MW eligible to settle as a CfD will 
be:  (a) the lesser of the RBP Resource’s committed RBP UCAP MW for a Delivery Year, 
daily owned UCAP MW, and daily RPM cleared UCAP MW.  Where the RBP Resource 
experiences a partial shortfall—meaning the quantity of MW (UCAP) that a resource clears 
is greater than the amount the resource actually owns, the CfD settlement will only count 
the daily owned UCAP MW.  In other words, there is no payment for undelivered RBP 
UCAP MW.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 87 
 
 
 
In addition, as described above, see supra Part III.C.7, RBP Resources that fail to 
reach commercial operation in a Delivery Year for which the resource has been committed 
in the RBP will be subject to RBP shortfall charges unless the RBP Resource qualifies for 
one narrow exception.  RBP shortfall charges are equal to the product of the RBP 
Resource’s committed RBP UCAP MW shortfall and 20% of the RBP price.218  The 
resulting shortfall charge will be allocated as a credit to LSEs based on each LSE’s pro-rata 
allocation of RBP Charges.  Like RBP Charges, the RBP shortfall charges are settled daily.   
d. 
Example of RBP Resource Settlements of RBP MW 
Shortfalls, RBP shortfall charges, RPM Commitment 
Deficiency MW, and RPM Commitment Charges (proposed 
Tariff, Attachment DD, section 18.6(d)) 
Table 5, below, demonstrates how shortfalls of capacity procured and committed 
in the RBP and RPM can impact the total credits ultimately paid to an RBP Resource.  In 
Table 5, a hypothetical RBP Resource clears 50 MW in both the RBP and RPM but is 
ultimately 5 MW short.  In other words, although the RBP Resource cleared in the RBP 
for 50 MW, only 45 MW actually reach commercial operation.  Because a resource’s 
ELCC may vary from year to year, PJM is proposing that RBP shortfall charges not be 
assessed to RBP Resources that have reached commercial operation, even if such resources 
have only partially reached the full commitment of RBP UCAP MW.   
Nevertheless, if an RPM Resource experiences a shortfall of MW cleared in the 
RPM, the RPM Resource will be subject to the existing RPM shortfall penalties.  In 
Table 5, below, the hypothetical resource commits 45 MW in the RPM, which is equal to 
 
218 See Proposed Tariff, Attachment DD, section 18.6(d).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 88 
 
 
 
the resource’s daily owned MW and therefore does not have any deficiency MW in the 
RPM.   
Table 5. Resource Settlement ($/day)  
Where RBP Cleared MW = RPM Cleared MW,  
RBP Cleared MW > Daily Owned MW 
(RPM Cleared MW = 50 MW (UCAP), RBP Cleared MW = 50 MW (UCAP), Daily 
Owned MW = 45 MW (UCAP), RPM Committed MW = 45 MW (UCAP),  
RBP Shortfall 5 MW (UCAP), RPM Commitment Deficiency MW = 0 MW (UCAP)) 
 
 
 
 
 
 
RBP and RPM Prices 
Expected 
RBP 
Credits 
RPM Auction 
Credits  
 
RBP Settlement 
Credits  
Total Credits 
RBP 
Cleared 
MW * RBP 
Price 
RPM Cleared 
MW * RPM 
Price+ 
Lesser of 
Cleared or 
Owned MW * 
(RBP Price – 
RPM Price+) 
RPM Auction Credits + 
RBP Settlement Credits 
RBP Price >  RPM 
Price+  
RBP Price =$250   
RPM Price+ = $200 
50 MW * 
$250 = 
$12,500 
50 MW * $200 
= $10,000 
45 MW * ($250-
$200) = $2,250 
$12,250 
RBP Price < RPM Price+  
RBP Price =$200   
RPM Price+ = $250 
50 MW * 
$200 = 
$10,000 
50 MW * $250 
= $12,500 
45 MW * ($200-
$250) = 
-$2,250 
$10,250 
RBP Price = RPM Price+ 
RBP Price =$250   
RPM Price+ = $250 
 
50 MW * 
$250 = 
$12,500 
50 MW * $250 
= $12,500 
45 MW * ($250-
$250) = $0 
$12,500 
+Or, in the event resource clears in multiple RPM Auctions, RPM WARCP) 
 
In Table 6, below, the hypothetical RBP Resource experiences a full RBP shortfall.  
In addition, the RPM has a lower UCAP available due to a decrease in ELCC.  The 
hypothetical RBP Resource clears 50 MW in the RBP but only clears and commits 49 MW 
in the RPM due to the ELCC decrease.     
Ultimately, the daily owned UCAP MW is 0 MW, because the resource has failed 
to reach commercial operation.  The hypothetical RBP Resource in this example has not, 
as yet, failed to reach commercial operation for three consecutive years, and therefore the 
RBP commitment has not been rescinded.  However, because the RBP Resource has not 
reached commercial operation, it is assessed an RBP shortfall charge.  In addition, because

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 89 
 
 
 
it has not reached commercial operation, the resource is also assessed an RPM 
Commitment Deficiency Charge for the 49 MW in the RPM.  Ultimately the result is a net 
charge (i.e., negative RBP Credit) to the seller. 
Table 6. Resource Settlement ($/day)  
Where RBP Cleared MW > RPM Cleared and Committed MW > Daily Owned MW 
(RPM Cleared MW = 49 MW (UCAP), RPM Committed MW = 49 MW (UCAP),  
RBP Cleared MW = 50 MW (UCAP), Daily Owned MW = 0 MW (UCAP), RBP 
Shortfall Penalty MW = 50 MW (UCAP), RPM Commitment Deficiency MW = 49 MW) 
 
 
 
 
 
 
RBP and 
RPM Prices 
Expected 
RBP 
Credits 
RPM 
Auction 
Credits  
 
RPM 
Commitment 
Charge 
RBP 
Settlement 
Credits  
RBP 
Shortfall 
Charges 
Total Credits 
RBP 
Cleared MW 
* RBP Price 
RPM 
Cleared 
MW * 
RPM 
Price+ 
RPM Commitment 
Deficiency MW * 
(120% RPM 
Price+) 
Lesser of 
Cleared or 
Owned MW * 
(RBP Price – 
RPM Price+) 
RBP 
Shortfall 
MW * (20%  
RBP Price) 
RPM Auction 
Credits – RPM 
Commitment 
Charge 
+ RBP Settlement 
Credits -RBP 
Shortfall Charges 
RBP Price >  
RPM Price+  
RBP Price 
=$250   
RPM Price+ 
= $200 
50 MW * 
$250 = 
$12,500 
49 MW * 
$200 = 
$9,800 
49 MW * (120% * 
$200) =$11,760 
0 MW * 
($250-$200) = 
$0 
50 MW * 
(20% * 
$250) = 
$2,500 
-$4,460 
RBP Price < 
RPM Price+  
RBP Price 
=$200   
RPM Price+ 
= $250 
50 MW * 
$200 = 
$10,000 
49 MW * 
$250 = 
$12,250 
49 MW * (120% * 
$250) = $14,700 
0 MW * 
($200-$250) = 
$0 
50 MW * 
(20% * 
$200) = 
$2,000 
-$4,450 
RBP Price = 
RPM Price+ 
RBP Price 
=$250   
RPM Price+ 
= $250 
 
50 MW * 
$250 = 
$12,500 
49 MW * 
$250 = 
$12,250 
49 MW * (120% * 
$250) = $14,700 
0 MW * 
($250-$250) = 
$0 
50 MW * 
(20% * 
$250) = 
$2,500 
-$4,950 
+Or, in the event resource clears in multiple RPM Auctions, RPM WARCP) 
10. 
Non-payment of RBP Charges and RBP shortfall charges (proposed 
Tariff, Attachment DD, section 18.9) 
To the extent an LSE defaults and fails to pay an RBP Charge, PJM will allocate 
the defaulted amount to all remaining LSEs that have been assigned responsibility for RBP 
Charges in the Electric Distributor zone/area based on each LSE’s pro-rata share of the

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 90 
 
 
 
total RBP Charges, as allocated based on either the Reliability Backstop Obligation or 
PJM’s back-up cost allocation methodology. 
Where an RBP Resource that is subject to RBP shortfall charges ultimately defaults 
and fails to pay the RBP shortfall charges, LSEs will not be allocated or charged those 
corresponding credits.  Thus, LSEs that would have otherwise paid for the RBP UCAP MW 
will not be responsible for covering the cost of the UCAP MW that were not delivered. 
RBP Resource subject to RBP shortfall charges pursuant to proposed Tariff, 
Attachment DD, section 18.6(d) defaults on RBP shortfall charges, the corresponding 
credits will not be allocated to the LSEs that would otherwise receive the RBP shortfall 
credits.   
11. 
Change in ownership of RBP Resource (proposed Tariff, 
Attachment DD, section 18.6(f)) 
Commitments of RBP UCAP MW follow the RBP Resource.  With change in 
ownership of the RBP Resource, the commitment of RBP UCAP MW will be conveyed to 
the new owner and continue through the end of the fixed 15-year term. 
D. 
Treatment of RBP Commitment in Event of Transmission Owner Exit 
During Term of the Commitment (Proposed Tariff, Attachment DD, 
section 18.7) 
As RBP commitments will remain in place through the 2042/2043 Delivery Year, 
i.e., for a fixed, 15-year term, PJM is also proposing rules that set forth the responsibilities 
of various parties in the event a Transmission Owner exits from PJM.  While it is true that 
no Transmission Owner has formally sought to exit PJM at this time, should such an event 
occur during the term of an RBP commitment in an exiting Transmission Owner’s territory,

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 91 
 
 
 
clear and enforceable rules will ensure that RBP commitments are honored through the 
term of the agreement.   
Establishing those rules now, with 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 cost certainty afforded developers in a 
15-year commitment, which will aid the financing RBP Resources that can be developed 
and placed in service quickly.  Without this 15-year guarantee, the financing terms and 
conditions associated with developing an RBP Resource would likely be significantly 
different, alter the total cost to build the resource, and potentially result in fewer resources 
being offered into the RBP at higher prices.  Therefore, however remote the possibility of 
a Transmission Owner exiting PJM during or prior to the 2042/2043 Delivery Year, it is 
imperative that rules are in place to ensure that, even in the event of a Transmission Owner 
exit, committed RBP Resources will be made whole for the entire term of the commitment. 
If a Transmission Owner leaves PJM and the load taken with the Transmission 
Owner is commensurate with the RBP Resources that are located in that Transmission 
Owner’s territory, the Transmission Owner is expected to honor the remaining term of the 
RBP commitment since it would need such resources to serve the loads in its service 
territory.  However, in the event a Transmission Owner exits PJM and committed RBP 
Resources are physically in such Transmission Owner’s service territory, it would be 
unreasonable for PJM’s Members to continue paying for such excess RBP Resources if

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 92 
 
 
 
they no longer can provide capacity to PJM (e.g., if the resource cannot be pseudo-tied into 
PJM as further explained below).219  
Similarly, in the event a Transmission Owner exits PJM with the net load that is 
removed with the Transmission Owner’s departure, it would be unreasonable for PJM’s 
remaining load to pay for the excess committed RBP Resources that remain in the PJM 
Region.  To address these potential scenarios, proposed Tariff, Attachment DD, sections 
18.7(a) and 18.7(b) put committed RBP Resources back in the same position they would 
have been in had the associated Transmission Owner not exited PJM. 
1. 
Committed RBP Resources in exiting Transmission Owner territory 
(proposed Tariff, Attachment DD, section 18.7(a)) 
Where 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.220  
The Transmission Owner effectively steps into PJM’s role in the RBP context.  In this way, 
the Transmission Owner that leaves PJM will be responsible for honoring the commitment 
to pay the impacted RBP Resources that may be located in such Transmission Owner’s 
service territory for the remaining term of the commitment.  At the same time, the existence 
of such an agreement would relieve PJM of any applicable RBP Obligations (“RBO”) made 
to RBP Resources that are subject to such agreements. 
 
219 See Transmittal, Part III.D. 
220 Proposed Tariff, Attachment DD, section 18.7(a).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 93 
 
 
 
In the event 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, thus allowing such resources to continue providing capacity to serve 
PJM’s load.221  Since the electric distance test may not necessarily be satisfied through 
network upgrades or other financial arrangements depending on where an RBP Resource 
may be located within an exiting Transmission Owner’s service territory, PJM proposes to 
exempt impacted RBP Resources from the electrical distance test to allow for such 
resources to be pseudo-tied back into PJM.222  Exempting the electric distance test for the 
limited pool of RBP Resources that are impacted should a Transmission Owner leave PJM 
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.  All other pseudo-tie requirements to qualify as capacity set forth in 
Tariff, Attachment DD, section 5.5A would continue to apply to any RBP Resource that 
PJM elects to retain and the Transmission Owner would be expected to pay for any 
necessary costs to pseudo-tie such impacted RBP Resources prior to exiting PJM.  
Mechanically, PJM would collect such costs from the exiting Transmission Owner and 
transfer the collected revenue to the impacted RBP Resources.  
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 
 
221 Id. 
222 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 94 
 
 
 
accelerated basis prior to exiting PJM.223  The exact amount that an exiting Transmission 
Owner would owe would be determined through a separate filing with the Commission.  
Thereafter, PJM would pay the collected revenues from the Transmission Owner to the 
impacted RBP Resource(s) as payments are due under the normal course of the 
commitment.   
2. 
Load allocated RBP Charges in exiting Transmission Owner 
territory (proposed Tariff, Attachment DD, section 18.7(b)) 
In the event that 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 RBP 
Resource(s).  PJM and PJMSettlement would then be relieved of applicable RBP 
Obligations to the RBP Resources.224  
Alternatively, absent such an agreement, such Transmission Owner would be 
required 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 under 
the Federal Power Act with approval from the Commission.225  This will 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 
 
223 Id. 
224 Proposed Tariff, Attachment DD, section 18.7(b). 
225 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 95 
 
 
 
Transmission Owner’s service territory.  Mechanically, the revenues collected from the 
Transmission Owner will be credited to the remaining loads in the PJM Region responsible 
for paying RBP Charges.  The amount 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.  
While the exiting Transmission Owner would be initially responsible to pay for the 
costs necessary to ensure no RBP Resource becomes a stranded asset, nothing in PJM’s 
proposal would preclude such a Transmission Owner from seeking to recover any such 
costs from the relevant large loads. 
3. 
Rules governing treatment of RBP Resources or load allocated RBP 
Charges in the event of Transmission Owner exit are appropriately 
submitted with this filing.  
The NEDC/PJM Governors’ Principles include “15-year price certainty for new 
capacity resources.”226  Price certainty includes protections against supply or demand 
becoming unavailable to serve the PJM Region as a result of a Transmission Owner’s 
decision to exit PJM.  The proposed rule provides stakeholders with ample notice.  Sellers 
of RBP Resources can be assured that the underlying inputs to their financing terms (i.e., 
firm price on a specified term) will not change in the event a Transmission Owner does exit 
from PJM during the term of the RBP commitment.  Furthermore, setting forth the rules in 
the Tariff now, even before the RBP offer window has opened, avoids any potential 
 
226 NEDC/PJM Governors’ Principles at 1.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 96 
 
 
 
arguments that changes to cost allocation associated with the RBP Resources after the 
commitments have already made may be impermissibly retroactive.  
4. 
The proposed rules governing treatment of RBP Resources or load 
allocated RBP Charges in the event of Transmission Owner exit are 
appropriately set forth in Tariff, Attachment DD. 
In the event of a Transmission Owner’s exit from PJM, the treatment of RBP 
Resources and load that has been allocated RBP Charges is, at bottom, a matter of close-out 
or settlement consequences of the RBP and thus properly addressed in Tariff, 
Attachment DD.  The departing RBP Resource’s UCAP MW and/or the departing load’s 
proportional share of the remaining term CfD are both incident to the RBP framework.  In 
other words, although the process impacts Transmission Owners, they 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.227  The 
proposed provisions address a substantive aspect of how RBP Resources should be treated 
throughout the 15-year commitment.   
E. 
Allocation of Costs Associated with Resources Procured Through the 
RBP (Proposed Tariff, Attachment DD, section 18.3) 
1. 
The proposed cost allocation methodology 
PJM is proposing to allocate daily RBP Charges to relevant Electric Distributor 
zones/areas, pro rata, based on the zone/area’s assigned share of the total, region-wide Final 
 
227 See Duquesne Light Co., 189 FERC ¶ 61,181, at P 55 (2024) (finding it not just and reasonable to include 
substantive transmission planning procedures in the CTOA, as the provisions do not affect only (or 
predominately) the rights and responsibilities of PJM and transmission owners), order addressing arguments 
raised on reh’g, 192 FERC ¶ 61,051 (2025).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 97 
 
 
 
RBP Target MW, floored at zero,228 and in accordance with RAA Schedule 8, as revised 
in 2024 to incorporate Load Adjustments in equations that “specify that load forecasts will 
be adjusted by zone/area and specifically include a variable for Load Adjustments[.]”229   
Cost responsibility allocated to a zone/area may be further adjusted where PJM 
receives sufficient evidence demonstrating that new capacity has been brought by load to 
the relevant Electric Distributor’s zone/area in the form of Qualifying RBP Offset UCAP 
MW.230  A zone/area of an Electric Distributor that qualifies for one of the opt-outs set 
forth in proposed Tariff, Attachment DD, section 18.1(d), would also have RBP Charges 
reduced by the MW quantity of the opt-out.231     
For each zone/area to which cost responsibility for RBP Charges has been allocated, 
PJM’s methodology sets forth rules for the further allocation of RBP Charges to LSEs 
within the relevant Electric Distributor’s zone/area.232  Ms. Croop’s affidavit provides a 
step-by-step explanation and example of how the proposed cost allocation methodology is 
applied to an Electric Distributor zone/area and then to the LSEs within the zone/area.233   
PJM is proposing that cost allocation to LSEs within an Electric Distributor’s 
zone/area be based on “the state and/or RERRA-determined allocation of cleared RBP 
UCAP MW to LSEs within each Electric Distributor’s zone/area, as reported by each 
 
228 Proposed Tariff, Attachment DD, section 18.3(a). 
229 PJM Interconnection, 188 FERC ¶ 61,200 at P 43. 
230 Proposed Tariff, Attachment DD, section 18.2(c). 
231 Proposed Tariff, Attachment DD, section 18.1(d). 
232 Proposed Tariff, Attachment DD, section 18.3(a). 
233 Croop Aff. ¶¶ 42-52.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 98 
 
 
 
Electric Distributor to [PJM].”234  PJM has thus created a new defined term, the “RBP 
Obligation” or “RBO”, to refer to this state and/or RERRA-determined allocation of RBP 
UCAP MW to LSEs within each zone/area.235  The RBO is flexible.  For example, it 
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, 
generally.  PJM’s authority over wholesale markets does not extend to dictating the 
allocation of costs to retail load, data centers and other large loads and, for purposes of cost 
allocation to such data centers and other large loads, each state and/or RERRA may have 
its own methodology, developed in accordance with its unique needs and considerations.        
PJM’s proposal requires that Electric Distributors report, to PJM, the state and/or 
RERRA-determined allocations of RBP UCAP MW to LSEs in their zone(s)/area(s).  To 
the extent that Electric Distributors report RBOs, the RBP Charge assessed daily to an LSE 
in the relevant zone/area will equal the LSE’s daily reported RBO MW in the zone/area 
divided by the total daily RBO MW in the zone/area, and multiplied by the total, daily RBP 
Charges allocated to the zone/area.   
In the unexpected event that RBOs are ultimately not reported to PJM, PJM will 
still need to proceed with settlement of the RBP Charges.  In this case, PJM will rely on a 
back-up cost allocation methodology to determine allocation to LSEs.  PJM’s back-up 
methodology applies PJM’s status quo method for allocating capacity costs pursuant to 
 
234 Proposed Tariff, Attachment DD, section 18.3(b)(iii). 
235 Proposed Tariff, Definitions – RBP Obligation (‘“RBP Obligation’ or ‘RBO’ shall mean the state and/or 
RERRA-determined allocation of RBP UCAP MW to Load Serving Entities within each Electric 
Distributor’s zone/area.”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 99 
 
 
 
RAA, Schedule 8,236 which incorporates Load Adjustments for purposes of allocating 
capacity costs to LSEs.  In other words, if no allocation is reported by the relevant Electric 
Distributors with allocated RBP UCAP MW, PJM will allocate RBP Charges based on the 
Peak Load Contribution submitted to PJM for the LSEs in the relevant zone/area. 
Importantly, PJM is not proposing a backup methodology for how RBP Charges 
should be allocated to non-jurisdictional, retail customers served by each of the LSEs in 
any Electric Distributor’s zone/area.  Even if Electric Distributors do not report any state 
and/or RERRA-determined RBOs in their zone(s)/area(s), and even if PJM subsequently 
applies the status quo allocation methodology to PJM’s LSE customers, PJM would not, 
under the proposed methodology, determine any further allocation to retail customers 
served by those LSEs.   
PJM and the PJM states and/or RERRAs must cooperate to ultimately allocate 
wholesale costs to end use, retail customers.  In the Commission’s 2007 order on rehearing 
affirming its finding that PJM’s RPM market design was just and reasonable, the 
Commission noted that the “question of jurisdiction over resource adequacy is a complex 
matter that stands at ‘the confluence of state-federal jurisdiction.’”237  The proposed RBP 
methodology recognizes and respects this division of responsibility.  While it is within 
PJM’s purview to allocate the costs of RBP Resources to LSEs, who are customers of PJM, 
the Commission has also recognized that it is beyond the scope of PJM’s authority to 
 
236 Proposed Tariff, Attachment DD, section 18.3(b)(iii) (“If no RBO MW are reported to the Office of the 
Interconnection in an Electric Distributor zone/area, PJM will allocate the RBP Charges for that zone/area to 
all load in the zone/area using each LSE’s ratio share of the Daily Unforced Capacity Obligation for the 
zone/area as determined in RAA, Schedule 8.  PJMSettlement shall be the Counterparty to each LSE’s 
obligation to pay, and payments of, RBP Charges.”).    
237 PJM Interconnection, 119 FERC ¶ 61,318 at P 40.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 100 
 
 
 
“address how LSEs [will subsequently] bill retail customers for such charges” as doing so 
would affect the “ability [of the PJM states and/or RERRAs] to allocate such charges.”238  
Thus, PJM’s proposed methodology for allocating RBP Charges sets the table for states 
and/or RERRAs, by empowering them to make decisions about how to best further allocate 
RBP Charges to data centers and other retail customers.   
2. 
The proposed method of allocating costs to Electric Distributor 
zones/areas and LSEs within those zones/areas is just and 
reasonable 
 
PJM is proposing to allocate daily RBP Charges to buyers in a manner that reflects 
careful consideration of cost causation and cooperative federalism principles, with an eye 
towards legal durability.   
First, the allocation of daily RBP Charges to relevant zones/areas, and the proposed 
back-up allocation methodology to LSEs served in those zones/areas in the absence of a 
state-determined methodology, rely on cost allocation methodologies set forth in RAA, 
Schedule 8239  that the Commission has already found just and reasonable.  
The Commission, in 2024, accepted PJM’s proposed revisions to RAA, Schedule 8 
“to better allocate, to zones/areas, localized load adjustments used to determine capacity 
obligations for [LSE].”240  These 2024 revisions to the RAA were, as PJM noted at the 
 
238 Commonwealth Edison Co., 133 FERC ¶ 61,118, at P 12 (2010). 
239 Proposed Tariff, Attachment DD, section 18.3(b)(iii). 
240 PJM Interconnection, 188 FERC ¶ 61,200 at P 1.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 101 
 
 
 
time, “spurred by the recent proliferation of data centers that are contributing to large 
additions of forecasted load concentrated within a specific wholesale metering area.”241   
The Commission’s 2024 order on those revisions found that PJM’s proposed Load 
Adjustments at the zone/area level were “just and reasonable because PJM propose[d] to 
assign increases or decreases in forecasted load to the zone/area in which the change 
occurs.”242  The proposed equations for allocating Load Adjustments “more accurately 
assign capacity obligations to LSEs.”243  The Commission furthermore found that it was 
appropriate for the relevant Electric Distributor to serve as “the party with the distribution 
and metering facilities defining a zone/area and responsible for reporting load information 
to PJM.”244     
Second, to the extent that PJM, under the proposed cost allocation methodology, 
further refines costs allocated to specific Electric Distributor zones/areas based on evidence 
that a zone/area has Qualifying RBP Offset UCAP MW, PJM’s proposal recognizes the 
importance of further adjusting allocations in zones/areas to reflect additional, new 
capacity to the extent that such capacity was not previously captured by the forecast and 
Load Adjustments.  Incorporating Qualifying RBP Offset UCAP MW into the allocation 
is intended to better align beneficiaries with costs and, in particular, to provide a 
mechanism to avoid allocating costs to LSEs that have already paid for new capacity to 
 
241 PJM Interconnection, L.L.C., Proposal to Better Account for Large Load Adjustments in Forecasted 
Capacity Obligations of PJM Interconnection, L.L.C., Docket No. ER24-2447-000, Transmittal at 1 (July 1, 
2024). 
242 PJM Interconnection, 188 FERC ¶ 61,200 at P 37. 
243 Id. 
244 Id. at P 40.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 102 
 
 
 
support their needs.  Thus, the proposed allocation relies on a Commission-accepted 
methodology, with adjustments to recognize Qualify New UCAP MW that may reduce the 
allocation to a particular zone/area.  By reducing allocated load further based on Qualifying 
RBP Offset UCAP MW, the proposed methodology guards against assigning costs to those 
who will not benefit from the addition of the new capacity procured through the RBP.   
Third, the proposed methodology assigns costs roughly commensurate with 
benefits to load.245  Cost causation requires that “all approved rates reflect to some degree 
the costs actually caused by the customer who must pay them.”246  Indeed, as the courts 
have held, “[n]othing requires the Commission to ensure full or perfect cost causation,”247 
and the Commission “is not bound to reject any rate mechanism that tracks the cost 
causation principle less than perfectly.”248  The load forecast, which reflect Load 
Adjustments in each zone/area, as further decremented by Qualifying RBP Offset UCAP 
MW, applies the information available to PJM, at the level of granularity that PJM has at 
its disposal, based on equations that “allow PJM to allocate a capacity obligation associated 
with a load adjustment to the zone/area in which the adjustment occurs.”249  In other words, 
PJM relies on the best information available in the short time before the commencement of 
 
245 Ill. Com. Comm’n v. FERC, 576 F.3d 470, 477 (7th Cir. 2009) (requiring “an articulable and plausible 
reason to believe that the benefits are at least roughly commensurate with [the costs.]”); Transmission 
Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, 136 
FERC ¶ 61,051, at PP 622, 639 (2011) (requiring costs of regional transmission facilities to be allocated in a 
manner that is at least roughly commensurate with estimated benefits), order on reh’g & clarification, Order 
No. 1000-A, 139 FERC ¶ 61,132, order on reh’g & clarification, Order No. 1000-B, 141 FERC ¶ 61,044 
(2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014) (“South Carolina PSA”).   
246 K N Energy v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992) (emphasis added); see also Midwest ISO 
Transmission Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004). 
247 South Carolina PSA, 762 F.3d at 88.    
248 Sithe/Indep. Power Partners, L.P. v. FERC, 285 F.3d 1, 5 (D.C. Cir. 2002) (citation omitted).  
249 PJM Interconnection, 188 FERC ¶ 61,200 at P 37.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 103 
 
 
 
the RBP on September 30, 2026.  PJM has tracked Load Adjustments in zones/areas to the 
level of granularity that is feasible.  As the United States Court of Appeals for the District 
of Columbia Circuit, in South Carolina PSA, held, “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.”250  The Commission’s approach to 
cost allocation is flexible by design.251 
The proposed zonal cost allocation methodology roughly assigns RBP Charges to 
the zones/areas with reported new load that is not matched with new capacity.  These 
zones/areas and LSEs can be said to have caused the resource adequacy shortfall reflected 
in the 2028/2029 Delivery Year BRA.  Applying the methodology set forth in RAA, 
Schedule 8, with adjustments for Qualifying RBP Offset UCAP MW, therefore, roughly 
assigns zones/areas that caused the shortfall with a share of the RBP Charges.  To be clear, 
states retain the authority to then further allocate these costs to retail customers, including 
data centers and other large loads, consistent with the Ratepayer Protection Pledge. PJM is 
addressing the allocation to specific zones but within those zones, the retail customer loads 
 
250 South Carolina PSA, 762 F.3d at 88 (internal quotation marks omitted) (quoting and citing Sithe/Indep. 
Power Partners, 285 F.3d at 5); Midwest ISO Transmission Owners, 373 F.3d at 1368-69; Pub. Serv. Comm’n 
of Wis. v. FERC, 545 F.3d 1058, 1066-67 (D.C. Cir. 2008); Carnegie Nat. Gas Co. v. FERC, 968 F.2d 1291, 
1293-94 (D.C. Cir. 1992) (noting that there is “no requirement in the Act itself that rates precisely match cost 
causation and responsibility” and that instead “the Commission may rationally emphasize other, competing 
policies and approve measures that do not best match cost responsibility and causation”).  
251 See, e.g., Ill. Com. Comm’n, 576 F.3d at 477 (“We do not suggest that the Commission has to calculate 
benefits to the last penny, or for that matter to the last million or ten million or perhaps hundred million 
dollars.” (citing Midwest ISO Transmission Owners, 373 F.3d at 1369 (“[W]e have never required a 
ratemaking agency to allocate costs with exacting precision.”))); Sw. Power Pool, Inc., 178 FERC ¶ 61,087, 
at P 30 n.42 (2022) (“Courts have held that the cost causation principle does not require costs to be allocated 
with exacting precision, but rather requires that costs be allocated in a manner ‘roughly commensurate’ with 
the benefits received.”) (citations omitted).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 104 
 
 
 
which have most contributed to the shortfall can be allocated the RBP costs consistent with 
state law as applicable. 
3. 
The proposed allocation methodology recognizes that allocation to 
retail customers, including data centers, is within the states’ and/or 
RERRAs’ purview  
The proposed cost allocation methodology assigns RBP costs in a manner that 
respects the balance of authority between states, the Commission, and PJM.252  Even in its 
infancy, the RPM required that the Commission “recognize the traditional role of state and 
local entities in regulating resource adequacy” while also remaining “aware of [its] 
responsibilities under the FPA to ensure that adequate service is provided, and that 
wholesale rates are just and reasonable.”253  Thus, the Commission found that the 
appropriate course of action was to “defer to state and local entities’ decisions when 
possible on resource adequacy matters, but in doing so . . . not shirk our 
congressionally-mandated responsibilities.”254   
First, the proposed cost allocation methodology empowers states and/or RERRAs 
to submit RBP RBOs, which PJM would then apply to the allocation of RBP Charges to 
LSEs.  However, under the proposed allocation framework, PJM would retain a back-up 
methodology for allocated RBP Charges to LSEs, which would apply if no RBOs are 
 
252 See U.S. Telecom Ass’n v. FCC, 359 F.3d 554, 567 (D.C. Cir. 2004) (“[A] federal agency entrusted with 
broad discretion to permit or forbid certain activities may condition its grant of permission on the decision of 
another entity, such as a state, local, or tribal government, so long as there is a reasonable connection between 
the outside entity’s decision and the federal agency's determination.”); see also PJM Interconnection, 119 
FERC ¶ 61,318 at P 40 (Commission noting that it will “defer to state and local entities’ decisions when 
possible on resource adequacy matters, but . . . will not shirk our congressionally-mandated 
responsibilities.”). 
253 PJM Interconnection, 119 FERC ¶ 61,318 at P 40 (i.e., requiring PJM to “allocate costs to data centers” 
as urged in the NEDC/PJM Governors’ Principles at 1). 
254 Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 105 
 
 
 
reported for a particular zone/area.  PJM’s proposed Tariff language expressly provides 
states and/or RERRAs with the opportunity, within PJM’s proposed cost allocation 
framework, to submit state-determined RBOs.  This back up cost allocation methodology 
is needed, because if no RBOs are reported for a particular zone/area, PJM would still need 
to allocate the RBP costs in a manner that is just and reasonable. 
PJM’s approach finds support in the Commission’s 2025 order accepting 
Midcontinent Independent System Operator, Inc.’s (“MISO”) Revised Expedited Resource 
Addition Study (“ERAS”) Proposal.255  In that matter, Commission found that RERRA 
participation in the ERAS process was permissible and not an improper delegation of 
federal authority to the states, as the participation of RERRA:  
would be wholly pursuant to a Commission-jurisdictional 
process . . . proposed by MISO and approved by the Commission—
not by state authorities—and under which a [Generator 
Interconnection Procedure] is on file with the Commission and any 
future revisions would be subject to Commission approval.  Further, 
the ERAS process would remain subject to the Commission’s 
authority pursuant to FPA sections 205 and 206.  In contrast, in 
Talen, the Maryland Commission established a state program that 
operated outside a Commission-jurisdictional process and 
“interfered” with the Commission’s authority to establish interstate 
wholesale rates.256 
Similarly, if accepted, PJM’s proposed cost allocation methodology would be set 
forth expressly in its Tariff, approved by and on file with the Commission.  The Tariff 
would expressly permit states and/or RERRAs to participate in the cost allocation of RBP 
 
255 Midcontinent Indep. Sys. Operator, Inc., Revisions to the Open Access Transmission, Energy and 
Operating Reserve Tariff Expedited Resource Addition Study Filing of Midcontinent Independent System 
Operator, Inc., Docket No. ER25-2454-000 (June 6, 2025). 
256 Midcontinent Indep. Sys. Operator, Inc., 192 FERC ¶ 61,064, at P 99 (2025) (distinguishing Hughes v. 
Talen Energy Mktg., LLC, 578 U.S. 150, 163 (2016)), order addressing arguments raised on reh’g, 194 
FERC ¶ 61,050 (2026).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 106 
 
 
 
costs to LSEs by reporting RBOs, which would supplant PJM’s backup allocation 
methodology of RBP Charges to LSEs.  Like MISO’s Revised ERAS Proposal, the 
proposed cost allocation methodology would nevertheless remain subject to the 
Commission’s authority pursuant to FPA sections 205 and 206.   
Second, PJM’s proposed cost allocation methodology hews closely to the 
Commission’s most recent articulation of where the boundary between state/RERRA and 
federal jurisdiction exists with respect to large loads.  Namely, while noting concerns 
“about the impact that large load additions can have on retail ratepayers, particularly the 
concern that other retail ratepayers may be forced to subsidize Network Upgrades needed 
to add large loads to the transmission system[,]” the Commission found that, in this realm, 
the scope of its regulatory authority is limited.257  “Specifically,” it is the PJM states that 
“have authority over how the wholesale costs of providing electricity, including 
transmission of such electricity, to those retail customers are recovered through retail 
rates.”258   
PJM’s cost allocation framework recognizes the need to protect retail ratepayers 
from subsidizing new capacity procured to serve large loads while also recognizing PJM’s 
own jurisdictional limitations.  As the Commission has found, it is the PJM states and/or 
RERRAs that have authority over how wholesale costs of these new capacity resources are 
recovered from retail customers through retail rates.  In fact, PJM does not have a line of 
sight into the retail load and end-use customers served by each relevant LSE.  PJM also 
recognizes that states may each define “large loads” and “data centers” differently.  Thus, 
 
257 June 2026 Order to Show Cause, 195 FERC ¶ 61,211 at P 69. 
258Id.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 107 
 
 
 
a cost allocation methodology that provides PJM states and/or RERRAs with the ability to 
determine the specific RBOs that should be assigned to LSEs, as well as to cost allocate to 
end-use customers in their respective states in accordance with their laws and policies, 
supports the NEDC/PJM Governors’ Principles, which include the principle that the cost 
of new capacity should be allocated to data centers who have caused the need for additional 
capacity in the PJM Region.   
Third, PJM’s proposed framework is pragmatic.  In the short time remaining before 
the September 30, 2026 RBP, it would simply be infeasible for PJM to obtain detailed 
information about the large loads and the various LSEs serving such large loads from every 
state and RERRA in the PJM Region.  States and RERRAs are simply in a better position 
to identify and cost allocate RBP Charges to large loads, including data centers, and the 
LSEs that serve them.  States and RERRAs have granular information about large loads 
within their borders.  Accordingly, PJM’s proposed cost allocation methodology 
deliberately leaves states and RERRAs with the flexibility to protect their own customers 
by allocating the costs of the procurement accordingly.  Furthermore, PJM’s proposal 
recognizes that state laws on the allocation of capacity costs to large loads, including data 
centers, are evolving.  The proposal recognizes and relies on the pledges of the 13 
governors of the PJM states 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 . . . [a]uctions to new 
data center loads that have not otherwise procured capacity or agreed to be curtailable.”259  
 
259 NEDC/PJM Governors’ Principles at 2.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 108 
 
 
 
However, to the extent that states and/or RERRAs do not provide such information, PJM 
will rely on Commission-approved cost allocation methodologies in place today to properly 
allocate costs to Electric Distributor zones/areas and LSEs.   
The proposed methodology addresses the consumer protection goals that have been 
raised by the National Energy Dominance Council, PJM’s 13 state governors, and other 
state and federal entities, while heeding the Commission’s recent articulation of the 
boundary between state and federal jurisdiction.    
F. 
Credit Requirements of RBP Resources and LSEs Commensurate with 
Risks (Proposed Tariff, Attachment DD, Section 18.8) and Management 
of RBP Defaults (Proposed Tariff, Attachment DD, Section 18.9) 
PJM is proposing to require both individual sellers (i.e., RBP Sellers) and buyers 
(i.e., LSEs) of RBP UCAP MW to provide RBP Collateral.260  While RBP Sellers must 
satisfy credit requirements prior to or simultaneously with submitting an RBP Sell Offer, 
LSEs will not be required to post credit until the first Delivery Year in which RBP 
Resources are expected to be in service (i.e., 2028/2029), once the allocation of cost 
responsibility for RBP UCAP MW has been determined for such Delivery Year.  The 
proposed RBP credit requirements apply in addition to and separate from existing 
collateral requirements, including collateral requirements associated with participating in 
RPM Auctions and engaging in RPM bilateral transactions.  Thus, PJM proposes to house 
the RBP credit rules in new section 18.8 of proposed Tariff, Attachment DD, and not 
 
260 PJM is proposing to add the definition of “RBP Collateral” to make clear the forms of collateral acceptable.  
Specifically, RBP Collateral “shall mean:  either (1) a cash deposit, including any interest thereon, or (2) a 
letter of credit issued for the benefit of PJM or PJMSettlement, in an amount and form determined by and 
acceptable to PJM or PJMSettlement as credit support.”  Proposed Tariff, Definitions – RBP Collateral.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 109 
 
 
 
alongside PJM’s more long-lasting credit rules in PJM’s Credit Risk Management Policy 
in Tariff, Attachment Q. 
The proposed RBP credit requirements recognize the inherent risks associated with 
procuring new capacity to serve new, incoming load through long-term commitments.  
While long-term, 15-year commitments should incentivize the addition of capacity by 
providing new capacity resources with revenue certainty, the fact that the commitments are 
all for new resources—that require additional capital investment and development and face 
a number of other issues, including supply chain and permitting risks—means the risks of 
non-performance (i.e., not reaching commercial operation) or delayed delivery is more 
meaningful to the PJM Region and likelihood is greater than for resources competing in 
RPM Auctions.  Accordingly, there is a need for a discrete RBP credit requirement to 
support an RBP Sell Offer. 
Likewise, the principle, supported by the Ratepayer Protection Pledge,261 that large 
loads will cover the costs of the new capacity procured through the RBP—and that the 
costs will not become stranded costs, which would ultimately be socialized—requires 
collateral to be provided by those LSEs allocated cost responsibility for RBP Resources to 
sufficiently guard against default risk.  PJM recognizes that evolving markets, supply chain 
issues, the unprecedented and unexpected nature of a capacity shortfall stemming from the 
influx of large loads, and the pace of change in technology are indicators of risk.  Thus, 
like the credit requirements imposed on inherently riskier Financial Transmission Rights, 
 
261 Ratepayer Protection Pledge; Ratepayer Protection Pledge Announcement.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 110 
 
 
 
sellers and buyers of RBP UCAP MW are limited to providing RBP Collateral in the form 
of either cash deposit or Letter of Credit.262 
Nevertheless, PJM has also tailored the proposed RBP Seller credit requirements 
to not be so onerous that they unnecessarily discourage RBP participation.  The proposed 
collateral requirement applied to RBP Sellers and buyers balances covering risks of 
non-delivery (whether the RBP Resource fails to materialize or is delayed, or the LSE fails 
to pay RBP Charges) and incentivizing the addition of new capacity to the PJM Region.  
This is particularly true now as recent RPM Auctions alone have not procured sufficient 
capacity to meet the PJM Region’s reliability requirement.   
As discussed below, the RBP credit requirement will only apply as needed.  The 
RBP credit requirement will not attach to RBP Sellers or buyers until the RBP Sellers’ or 
buyers’ actions give rise to credit exposure.  Thus, RBP Collateral will be required of RBP 
Sellers as a condition of submitting RBP Sell Offers263 and must be posted either prior to 
submitting or along with RBP Sell Offers.  When an RBP Resource no longer gives rise to 
credit exposure, the RBP Collateral will be returned upon request.  Specifically, RBP 
UCAP MW that are offered but do not get committed through the RBP, RBP Resource 
commitments that are rescinded for failure to materialize after three Delivery Years, or 
RBP Resource that reach commercial operation and are no longer subject to the RBP 
shortfall charge may have their RBP credit requirement reduced accordingly.    
 
262 See Proposed Tariff, Definitions – RBP Collateral. 
263 Proposed Tariff, Definitions – RBP Sell Offer (“‘RBP Sell Offer’ shall mean an offer to sell RBP 
Resources in the Reliability Backstop Procurement.”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 111 
 
 
 
Buyers of RBP UCAP MW, i.e., LSEs that have been allocated cost responsibility 
for RBP Charges pursuant to proposed Tariff, Attachment DD, section 18.3, will be 
required to post RBP Collateral to mitigate the risk of potential defaults from non-payment 
of RBP Charges, while those LSEs not allocated cost responsibility generally will not have 
any credit requirement.264  As explained in the affidavit of Ms. Gwen Kelly, Senior Director 
in Credit Risk and Collateral Management for PJM, on behalf of PJM, a buyer’s credit 
requirement will start at an amount sufficient to mitigate the long-term risk of the RBP 
commitment at the beginning of the commitment term and decrease over time as the term 
winds down.265  
Such a buyer-side credit requirement is just and reasonable and received strong 
Member support in the stakeholder process.266  In any event, PJM has the obligation to 
appropriately mitigate risk of default through application of credit requirements and credit 
tools.  But, as noted above, the RBP’s unprecedented long-term commitment and 
corresponding long-term payment requirement are not contemplated by PJM’s existing 
 
264 Proposed Tariff, Definitions – RBP Charges (“‘RBP Charges’ shall mean the $/day value of the total RBP 
Settlement Credits, positive or negative, of all committed RBP Resources across the PJM Region.”).   
265 Affidavit of Gwen Kelly on Behalf of PJM Interconnection, L.L.C. (Attachment D) ¶ 29 (“Kelly Aff.”) 
(“PJM further considered how the payment exposure with the portfolio of committed RBP Resources changes 
over the 15-year commitment term.  PJM concluded that the remaining payment exposure naturally declines 
as remaining, forward RBP payment obligations are satisfied and as committed RBP Resources are removed 
from the portfolio through rescinded commitments or other changes affecting the remaining payment 
obligations.”). 
266  Indeed, as set forth in the PJM RBP Matrix, of the 13 RBP proposals put forth during the CIFP, seven of 
the proposals adopted the buy-side credit requirement set forth herein.  In addition, two of the proposals took 
no position on the matter.  See PJM Interconnection, L.L.C., MC Voting Results for RBP Proposals Agenda 
Items 3L through 3X, (June 30, 2026), https://www.pjm.com/committees-and-groups/committees/mc 
[https://perma.cc/5CSQ-DP4K] (scroll to “Meeting Materials” and search for 2026, click on link for 
“6.30.2026 Special Meeting,” scroll to MC Voting Results – Agenda Items 3L to 3X and click on each to 
view the PDF) (last visited July 29, 2026).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 112 
 
 
 
credit tools.  PJM’s proposed RBP credit rules address that gap and allow PJM to mitigate 
the new risks presented by RBP.267 
1. 
Sellers must provide collateral with RBP Sell Offers (proposed 
Tariff, Attachment DD, section 18.8(a)) 
 
PJM proposes that sellers provide RBP Collateral in accordance with credit 
requirements for each RBP Sell Offer before or concurrently with submitting an offer in 
the RBP.268   
For each RBP Sell Offer, the credit requirement is the sum of 20% of the RBP Sell 
Offer Price * RBP UCAP MW for each of the first three Delivery Years offered.  This is 
expressed formulaically in the proposed Tariff as: 
∑0.2 × (𝑅𝐵𝑃 𝑆𝑒𝑙𝑙 𝑂𝑓𝑓𝑒𝑟 𝑃𝑟𝑖𝑐𝑒 𝑖𝑛
$
𝑀𝑊𝐷𝑎𝑦) 𝑛× (𝑈𝐶𝐴𝑃 𝑖𝑛 𝑀𝑊)𝑛× 365
3
𝑛=1
 
where n = Delivery Year269 
As such, the RBP credit requirement appropriately reflects (and matches) the seller’s ability 
to offer an RBP Resource at a different price and different UCAP commitment level for 
each Delivery Year for the first three years the RBP Resource is expected to be in service. 
This credit requirement is specific to each offered RBP Resource and is designed 
to cover three years of RBP shortfall charges for that resource.270  RBP shortfall charges 
 
267 See Kelly Aff. ¶ 19 (“PJM found that its current credit tools do not contemplate the long-term nature of 
RBP and the risk of future non-payment that results.”); id. ¶ 24 (“In developing that rate, PJM sought to 
establish an initial level of collateral that provides commensurate protection against non-payment while 
avoiding full collateralization of the entire 15-year contractual commitment.”).  
268 See proposed Tariff, Attachment DD, section 18.8(a). 
269 Proposed Tariff, Attachment DD, section 18.8(a)(iv); see also Kelly Aff. ¶ 13. 
270 See Kelly Aff. ¶ 14 (“[T]he RBP credit requirement reflects and matches (i) the seller’s ability to offer an 
RBP Resource at a different price and different UCAP commitment level for each Delivery Year for the first 
three years; and (ii) the requirement that an RBP Resource must reach commercial operation within three 
Delivery Years of its target in-service date.”).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 113 
 
 
 
are also based on 20% of the RBP Sell Offer Price and are applicable in the event the RBP 
Resource does not achieve commercial operation.  Credit requirement at this level covers 
the payment of any RBP shortfall charges, while not being so high as to deter entry of 
non-speculative RBP Resources.  As such, the credit requirement applicable to RBP Sell 
Offers will support the success of RBP in attracting the development of new capacity in 
the PJM Region. 
2. 
Return of RBP Collateral (proposed Tariff, Attachment DD, 
section 18.8(a)(ii)) 
Consistent with the risk mitigation logic driving the need for RBP Sellers to post 
RBP Collateral, such collateral shall be returned commensurate with reduction in risk.271  
First, PJM will return any RBP Collateral associated with “any RBP Resources that do not 
receive a commitment through the Reliability Backstop Procurement.”272  Second, PJM 
may return RBP Collateral associated with an RBP Resource that secured a commitment 
only after the resource achieves commercial operation and then after a one-year look-back, 
to allow PJM to confirm that steady commercial operation occurred.273   
3. 
Collateral requirements for RBP Resources traded to a different 
entity than the RBP Seller (proposed Tariff, Attachment DD, 
section 18.8(a)(v)) 
Given the risk of an RBP Resource not achieving commercial obligation and to 
incent continued development of committed RBP Resources in the event of a change in 
ownership, PJM proposes to retain the original RBP Seller’s RBP Collateral and financial 
 
271 See id. ¶ 15 (“Consistent with PJM’s objective of aligning collateral with the underlying financial 
exposure, PJM concluded that collateral should remain in place only while the associated performance risk 
continues to exist.”). 
272 Proposed Tariff, Attachment DD, section 18.8(a)(iii)(A). 
273 Proposed Tariff, Attachment DD, section 18.8(a)(iii)(B).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 114 
 
 
 
responsibility for a committed RBP Resource that is traded until the receiving party (i) 
independently posts sufficient credit with PJM and (ii) provides written confirmation to 
PJM of its agreement to “fully assume the credit responsibility associated with the 
committed RBP Resource.”274  This requirement ensures the credit associated with any 
committed RBP Resource that has not yet achieved commercial operation is maintained 
and an RBP Seller must consider the ability of the other entity to either (i) post sufficient 
credit or (ii) bring the RBP Resource to commercial operation.  Both considerations are for 
the benefit of the PJM Region and are just and reasonable.  This credit requirement for 
trading RBP Resources is consistent with the credit requirement for trading Capacity 
Resources committed through RPM.275 
4. 
Buyers (LSEs) allocated cost responsibility for RBP Charges must 
provide 
collateral 
(proposed 
Tariff, 
Attachment 
DD, 
section 18.8(b)) 
PJM is proposing to require that those LSEs allocated RBP cost responsibility for 
a given Delivery Year must post credit associated with such obligation.276  Such a credit 
obligation is just and reasonable, as it is designed to protect those LSEs not allocated cost 
responsibility for RBP Resources from having to pay for such resources.  To be clear, LSEs 
not allocated cost responsibility for RBP Resources will not have an RBP credit 
requirement.  This is consistent with the Ratepayer Protection Pledge and cost causation 
principles, as explained above.  
 
274 Proposed Tariff, Attachment DD, section 18.8(a)(v). 
275 See Tariff, Attachment Q, section VI.B.7 (Credit Responsibility for Traded Planned RPM Capacity 
Resources). 
276 See proposed Tariff, Attachment DD, section 18.8(b).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 115 
 
 
 
The purpose of the buyer-side credit requirement is to mitigate the risk associated 
with RBP commitments through the RBP commitment term.  The purpose of LSE credit is 
to mitigate potential defaults from non-payment of RBP credit obligations.277  PJM 
mitigates risk of default through credit requirements and credit tools.  This is particularly 
true where a procurement process locks in RBP payments for a fixed, 15-year term.  
Given this overall purpose, PJM will first determine the overall credit requirement 
needed to address this risk at an aggregate level before then determining an individual 
LSE’s credit requirement.278  PJM will determine the cumulative RBP credit requirement 
equal to “the product of the RBP Credit Rate multiplied by RBP UCAP MW 
committed.”279  That is, one uniform $/MW rate will be applicable to all committed RBP 
UCAP MW.  Once determined, PJM will apply this rate to set the RBP credit requirement 
for each LSE allocated cost responsibility for a given Delivery Year.  This approach 
appropriately achieves the purpose of mitigating potential defaults from non-payment of 
RBP Charges through the commitment term.   
a. 
Determining the inputs to the RBP credit requirement 
As can be seen, an LSE’s RBP credit requirement is a function of two inputs: the 
RBP Credit Rate and RBP UCAP MW committed.  Initially, the “committed RBP UCAP 
 
277 See Kelly Aff. ¶¶ 19-20 (“PJM evaluated the credit tools needed to mitigate potential defaults from 
non-payment of RBP Charges. . . . Based upon that evaluation, PJM determined that only those LSEs 
allocated responsibility for RBP Charges should be required to provide RBP Collateral.”). 
278 Ms. Kelly testifies that “PJM considered that the relevant financial exposure is created by the portfolio of 
committed RBP resources rather than by any individual LSE in isolation,” and therefore “PJM developed a 
methodology that first determines the aggregate collateral necessary to address the payment exposure 
associated with the portfolio of committed RBP Resources and then allocates that collateral requirement 
among the LSEs responsible for payment of RBP Charges.”  Kelly Aff. ¶¶ 21-22. 
279 Proposed Tariff, Attachment DD, section 18.8(b)(i)(A).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 116 
 
 
 
MW” input will equal the total amount of RBP UCAP MW committed through the 
Reliability Backstop Procurement.  But, that MW level will change as committed resources 
fail to follow through on their commitment and do not achieve commercial operation.  
Thus, to the extent any “commitment of RBP UCAP MW that is rescinded pursuant to 
Tariff, Attachment DD, section 18.6(e)” that value is subtracted from the input used to 
determine the uniform RBP credit requirement.280   
The other input to determining RBP credit requirement is the “RBP Credit Rate.”  
PJM proposes to set this input initially at $1.5 million.  Over time this rate “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, . . . to an 
amount sufficient to cover the total existing RBP Charges obligations.”281   
The initial $1.5 million figure is designed to adequately balance mitigating the risk 
of defaults from non-payment of RBP Charges associated with the RBP commitments 
without unduly burdening those Load Serving Entities serving large loads.  The initial $1.5 
million figure ensures that PJM holds sufficient collateral to cover approximately 50% of 
the notional value of all RBP commitments, which achieves PJM’s objective of 
establishing “an initial level of collateral that provides commensurate protection against 
non-payment while avoiding full collateralization of the entire 15-year contractual 
commitment.”282  This can be seen through the application of a simple formula based on 
 
280 Id. (“[T]he RBP UCAP MW committed amount shall equal the amount of RBP UCAP MW that receives 
a commitment through the Reliability Backstop Procurement minus each commitment of RBP UCAP MW 
that is rescinded pursuant to Tariff, Attachment DD, section 18.6(e).”). 
281 Proposed Tariff, Attachment DD, section 18.8(b)(i)(A). 
282 Kelly Aff. ¶ 24.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 117 
 
 
 
the RBP Charge obligation over 15 years, i.e., the commitment term, and a conservative 
assumption that all RBP commitments are—on average—at the maximum willingness to 
pay, i.e.,15 years * 365 days * $555/MW-Day = $3,038,625.  Roughly half of $3,038,625 
is $1.5 million, confirming that collateral at this level will cover approximately half the 
notional value of the contracted commitment from Day 1.  Ms. Kelly also performed a 
“check” on the reasonableness of the $1.5 million value through a discount cash flow 
model, which took each year’s RBP Charge Obligation, i.e., 1 year * 365 days * $555/MW-
Day = $202,575, discounted to September 2026, when the auction is conducted, using the 
discount rate of 9.5%.283  The discount rate is the capacity market Weighted Average Cost 
of Capital developed by the Brattle Group as part of PJM’s 2025 periodic review of the 
Cost of New Entry of Capacity Resources into the PJM Region.284   
Because the risks the RBP Collateral is designed to address will lessen over time, 
the $1.5 million per MW figure is an initial value.  PJM proposes to reduce this RPM Credit 
Rate value to correspond with decreasing risk over time.285  As Ms. Kelly testifies, “PJM 
developed a provision permitting reductions to the RBP credit rate when changes in the 
underlying RBP commitment portfolio demonstrate that previously required collateral 
exceeds the remaining expected payment exposure.”286  The risk could lessen for a number 
 
283 See id. ¶ 27. 
284 See id. ¶ 29 (citing The Brattle Group, Brattle 2025 CONE Report for PJM, PJM Interconnection, L.L.C., 
26-34 
(Apr. 
9, 
2025), 
https://www.pjm.com/-/media/DotCom/committees-
groups/committees/mic/2025/20250411-special/item-1-02-revised-cone-report-final.pdf 
[https://perma.cc/B3VN-EY34]). 
285 Proposed Tariff, Attachment DD, section 18.8(b)(i)(A) (“[T]he RBP Credit Rate shall equal $1.5 million, 
as may be reduced, for reasons including a change in the total committed RBP UCAP MW, when total posted 
RBP Collateral is greater than the total remaining RBP Charges obligations, over time by the Office of the 
Interconnection to an amount sufficient to cover the total existing RBP Charges obligations.”). 
286 Kelly Aff. ¶ 30.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 118 
 
 
 
of reasons, including a reduction in the total committed RBP UCAP MW—which would 
reduce the forward RBP Charge obligations, and as the total posted RBP Collateral 
becomes greater than the total remaining forward RBP Charges obligations.  This 
“approach aligns required collateral with the remaining financial exposure through the 
commitment term.”287   
b. 
Determining an LSE’s RBP credit requirement 
PJM proposes that the RBP credit requirement will follow cost allocation for RBP 
Resources.  In other words, only those LSEs allocated cost responsibility will be assigned 
an RBP credit requirement and be required to post RBP Collateral, and the RPM credit 
requirement will be based on the level of RBP UCAP MW for which an LSE is allocated 
cost responsibility.  In this manner, the RBP credit requirement will be aligned with cost 
allocation.288 
At a high level, an LSE’s RBP credit requirement will equal the product of (1) the 
uniform $/MW credit requirement rate and (2) the LSE’s RBP UCAP MW amount.  Thus, 
for LSEs serving load in an Electric Distributor zone/area in which no RBOs have been 
reported,289 an LSE’s “allocated RBP UCAP MW shall equal the Load Serving Entity’s 
pro-rata share of the Daily Unforced Capacity Obligation for the zone/area as determined 
in RAA, Schedule 8.”290 
 
287 Id. 
288 See id. ¶ 20 (“PJM determined that only those LSEs allocated responsibility for RBP Charges should be 
required to provide RBP Collateral.  Conversely, LSEs not allocated responsibility for RBP Charges do not 
present the payment exposure the proposed credit provisions are intended to address and therefore are not 
subject to the RBP credit requirement.”). 
289 See supra Part III.E.1 for a discussion of RBOs. 
290 Proposed Tariff, Attachment DD, section 18.8(b)(i)(B)(1).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 119 
 
 
 
For LSEs serving load in an Electric Distributor zone/area in which RBOs have 
been reported, the LSE will be required to post RBP Collateral for its RBO MW (i.e., its 
allocated RBP UCAP MW amount).  Consistent with the proposed cost allocation rules,291 
PJM proposes that “the RBP Obligation MW [will] equal[] the RBP Obligation MW 
submitted for the Load Serving Entity by the Electric Distributor and scaled, as necessary, 
in the event that the RBP Obligation MW values uploaded by the Electric Distributor do 
not sum to the fixed, Final RBP Target MW for the zone/area.”292 
While the forgoing should require the provision of adequate credit to mitigate the 
risk of paying for the RBP commitments over their term, that approach does not have the 
flexibility to address unreasonable credit risk that may arise in the RBP context.  Thus, 
because PJM is proposing to address RBP credit through rules outside of its Credit Risk 
Management Policy, PJM is proposing to include language allowing PJM to “evaluate 
whether such Load Serving Entity for unreasonable credit risk under the Unreasonable 
Credit Risk provisions of Tariff, Attachment Q, Section II, and require additional RBP 
Collateral as appropriate.”293  Such a provision is necessary and reasonable, because it 
ensures that PJM has unambiguous authority to manage unreasonable credit risk in the RBP 
context.  Indeed, while PJM also proposes that “[n]othing in this Tariff, Attachment DD, 
section 18 supersedes the provisions of Tariff, Attachment Q,”294 that provision does not 
provide clear authority.  The Commission has recognized the importance of managing 
 
291 See proposed Tariff, Attachment DD, sections 18.3(b)(i)-(ii). 
292 Proposed Tariff, Attachment DD, section 18.8(b)(i)(B)(1). 
293 Proposed Tariff, Attachment DD, sections 18.8(b)(i)(B)(1)-(2). 
294 Proposed Tariff, Attachment DD, section 18.8.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 120 
 
 
 
unreasonable credit risk to “protect the integrity of the PJM-administered markets, as well 
as protect market participants from financial losses that result from unreasonable credit 
risks and defaults.”295  And, here, PJM is providing sufficient “clarity and transparency” 
by grounding PJM’s evaluation in “the Unreasonable Credit Risk provisions of Tariff, 
Attachment Q, Section II.”296 
c. 
Posting and maintenance of RBP Collateral 
PJM is proposing that, “prior to forty-five (45) days before the start of the Delivery 
Year,” all LSEs with an RBP credit requirement “must post, or maintain an existing, RBP 
Collateral” equal to their RBP credit requirement.297  This allows time for Electric 
Distributors to work with their RERRAs in specifying the RBO MW for the relevant 
zone/areas, with  “the initial allocation reported no later than 60 days prior to the 2028/2029 
Delivery Year.”298  As a general matter, an LSE’s RBP credit requirement is not likely 
change based on the applicable Delivery Year.  Stated another way, a change in Delivery 
Year does not necessarily mean a change in RBP credit requirement.  Rather, changes in 
RBP credit requirement will only occur to the extent (1) the LSE’s allocated RBP UCAP 
MW level changes and/or (2) PJM changes the RBP Credit Rate, as discussed above.  
Accordingly, an LSE with an RBP credit requirement should have a good degree of 
certainty that its requirement will remain relatively constant, and generally only go down 
over time, if its allocated RBP UCAP MW does not change.  For this reason, PJM is making 
 
295 PJM Interconnection, L.L.C., 171 FERC ¶ 61,173, at P 36 (2020). 
296 Id. 
297 Proposed Tariff, Attachment DD, sections 18.8(b)(i)(B)(1). 
298 Proposed Tariff, Attachment DD, section 18.3(b)(iii).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 121 
 
 
 
explicit that the posted RBP Collateral can be maintained from one Delivery Year to the 
next; there is no need to recall and repost any RBP Collateral if the RBP credit requirement 
is not changing.   
However, to the extent an LSE’s allocated RBP UCAP MW level does change for 
a future Delivery Year, it must post the appropriate RBP Collateral at least 45 days in 
advance.  This timeframe affords PJM’s credit department to work with the LSE to ensure 
the LSE meets all applicable requirements.   
d. 
Changes to the RBP credit requirement associated with intra-
Delivery Year transfers of load and RBP UCAP MW cost 
responsibility 
Once determined, a credit requirement may be reduced during a Delivery Year to 
the extent the RBP UCAP MW allocated to the LSE are also reduced.299  Such a reduction 
in allocated RBP UCAP MW cost responsibility could occur where an LSE transfers its 
load serving obligations for a certain load to another LSE.  In such an event, the transferee 
LSE must satisfy the credit requirements associated with taking on such load serving 
obligation, including any cost allocation for the RBP UCAP MW associated with such 
transferred load.  Ms. Kelly explains that “PJM concluded that the underlying payment 
exposure associated with transferred RBP payment obligations remains until the receiving 
LSE independently satisfies the applicable collateral requirements and assumes 
responsibility for the transferred obligations.”300  Thus, PJM proposes that the “[t]ransferee 
shall independently post sufficient RBP Collateral directly with the Office of 
Interconnection to satisfy the incremental RBP UCAP MW associated with the acquired 
 
299 See proposed Tariff, Attachment DD, section 18.8(b)(i)(A). 
300 Kelly Aff. ¶ 32.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 122 
 
 
 
load.”301  The transferring LSE would then “be released from its financial obligations for 
amount of RBP Collateral associated with the RBP UCAP MW associated with the 
acquired load” and the LSE’s posted RBP Collateral associated with such load shall be 
returned once (i) the new LSE has posted the RBP Collateral; and (ii) “any unpaid invoice 
amounts associated with such transfer have been paid by the transferor.”302 
5. 
Management of defaults of obligations to pay RBP Charges and 
RBP shortfall charges (proposed Tariff, Attachment DD, 
section 18.9) 
Consistent with the Ratepayer Protection Pledge and cost causation principles, PJM 
proposes to circumscribe the consequences of defaults in the RBP context.  There are two 
payment obligations on which entities may default:  RBP Charges by LSEs, and RBP 
shortfall charges by the RBP Seller.  First, PJM proposes that, upon any LSE’s default of 
RBP Charges, the defaulted amounts shall be reallocated to among the other LSEs allocated 
RBP Charges based on their proportional share of the total RBP Charges assessed across 
the PJM Region.303  However, the amounts (re)allocated to these other LSEs may be offset 
by the RBP Collateral posted by the defaulting LSE.304  Such a rule is just and reasonable 
and protects against broad socialization of cost responsibility among not only LSEs not 
serving large loads but also the rest of PJM’s Members, as PJM’s Operating Agreement 
provides that, in the event a Member defaults on its payment obligations, the other PJM 
Members may be required to pay a share of defaulted amounts.305   
 
301 Proposed Tariff, Attachment DD, section 18.8(b)(i)(C)(1). 
302 Proposed Tariff, Attachment DD, section 18.8(b)(i)(C)(2). 
303 See proposed Tariff, Attachment DD, section 18.9(a). 
304 See id. 
305 See Operating Agreement, section 15.2.2.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 123 
 
 
 
Second, PJM proposes that, in the event an RBP Resource must pay RBP shortfall 
charges and it defaults on payment of such charges, then the LSEs that would have received 
corresponding credits will not receive such credits.306  This is reasonable, as there would 
be no monies to fund such credits to the LSEs.  However, to the extent the RBP Seller’s 
posted RBP Collateral has not been returned (e.g., because the resource achieved 
commercial operation), then PJM may be able to provide some level of credits to the 
appropriate LSEs from such collateral. 
G. 
Miscellaneous and Conforming Changes  
1. 
Reliability Backstop Auction (Tariff, Attachment DD, section 16.2) 
The RBP bears similarities to the Reliability Backstop Auction, which was 
established approximately 20 years prior to cover potential capacity shortfalls, as described 
in Tariff, Attachment DD, section 16.2.  As noted above, the RBP is a procurement 
framework that is specifically tailored to the circumstances of the present-day capacity 
shortfall and therefore provides benefits that a generic Reliability Backstop Auction would 
not.   
Under the current Tariff provisions, a Reliability Backstop Auction is triggered if, 
for three consecutive Delivery Years, the BRA “equates to an installed reserve margin that 
is more than one percentage point lower than the approved PJM Region Installed Reserve 
Margin.”307  The BRAs for the 2027/2028 and 2028/2029 Delivery Years resulted in an 
 
306 See proposed Tariff, Attachment DD, section 18.9(b) (“In the event that an RBP Resource subject to RBP 
shortfall charges pursuant to Tariff, Attachment DD, section 18.6(d) defaults on payment of RBP shortfall 
charges, the corresponding credits will not be allocated to the Load Serving Entities that would otherwise 
receive the RBP shortfall charge credits.”). 
307 Tariff, Attachment DD, section 16.2.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 124 
 
 
 
installed reserve margin that was more than one percentage point lower than the approved 
PJM Region Installed Reserve Margin.  In both the BRA for the 2028/2029 Delivery Year 
and the BRA for the 2027/2028 Delivery Year, the RPM cleared 5.6% below the PJM 
Region Installed Reserve Margin of 20%.308  Even with the intervention of the RBP, the 
2029/2030 Delivery Year BRA may clear short, as new capacity that qualifies for 
procurement in the RBP are required to provide evidence of feasibility of commercial 
operation by no later than June 1, 2032.  Unless the starting point for the three consecutive 
Delivery Years is reset, a Reliability Backstop Auction may be triggered and interfere with 
the RBP.  Thus, PJM is proposing to reset the Reliability Backstop Auction trigger by 
revising the Tariff to state that “[n]o Reliability Backstop Auction will be conducted to 
address such a shortfall unless it occurs in the Base Residual Auctions for three consecutive 
Delivery Years” beginning with the 2032/2033 Delivery Year and thereafter.309  Similarly, 
PJM proposes to specify that the existing requirement for PJM to investigate the cause for 
clearing short of the reliability requirement and to recommend corrective action be reset to 
the 2032/2033 Delivery Year.  Doing so avoids posting substantively repetitive reports 
should the BRAs continue to clear short in the intervening Delivery Years.310  The revision 
to the 2032/2033 Delivery Year will align the trigger of the Reliability Backstop Auction 
 
308 2027/2028 BRA Report at 1 (“PJM Interconnection cleared the 2027/2028 Base Residual Auction with a 
reserve margin that is more than one percentage point below the Installed Reserve Margin target, and with 
total Unforced Capacity of all Base Load Generation Resources less than the forecasted minimum hourly 
load. This confirmed shortfall constitutes a triggering event as defined in the PJM Tariff, mandating an 
investigation to determine the root causes of the region’s failure to secure sufficient resource adequacy.”); 
2028/2029 BRA Report at 3. 
309 Proposed Tariff, Attachment DD, section 16.2. 
310 PJM issued its first report in accordance with this requirement after the BRA for the 2027/2028 Delivery 
Year cleared short the reserve target on February 9, 2026.  See 2027/2028 BRA Report.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
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to begin  after the RBP Resources come online, allow time to observe the impact of 
commercial bilateral contracting whether through PJM’s Bilateral Matching efforts or 
otherwise, and the efforts underway that are outlined in PJM’s Powering Reliability 
Through Markets White Paper.  Revising the Reliability Backstop Auction trigger to the 
beginning of 2032/2033 avoids the possibility of an intervention through a Reliability 
Backstop Auction, until after all RBP Resources should have reached their respective 
commercial operation dates.  In addition, revising the Reliability Backstop Auction trigger 
provides time for the effects of PJM’s Bilateral Matching and other commercial bilateral 
contracting to be felt.  Furthermore, it provides time for the effects of PJM’s Powering 
Reliability Through Market’s efforts to be felt before potentially triggering a Reliability 
Backstop Auction.   
Resources procured in the RBP must demonstrate that commercial operation by the 
beginning of the 2032/2033 Delivery Year is feasible.  Thus, resetting the trigger for the 
Reliability Backstop Auction to the 2032/2033 Delivery Year recognizes that, even if the 
RBP successfully procures sufficient capacity to cover the shortfall, RBP Resources will 
need time to become operational.  Resetting the Reliability Backstop Auction thus ensures 
that the safeguard will remain in place without interfering with the RBP, which is being 
proposed to address a similar resource adequacy concern. 
2. 
Planned Generation Capacity Resource (Tariff, Attachment DD, 
section 5.5A) 
The existing rules limit the resources that are eligible to participate into the RPM 
Auctions.  In particular, a new generation resource would not be allowed to be offered into 
the RPM Auctions unless it meets the definition of a Planned Generation Capacity

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 126 
 
 
 
Resource.  As currently defined, a Planned Generation Capacity Resource must have met 
all of the requirements for an approved Decision Point I (for a resource that is 20 MW or 
less) or Decision Point II (for a resource that is greater than 20 MW).  This limitation exists 
to provide a gating criteria so that speculative projects or projects that are unlikely to be in 
service by the relevant Delivery Year would not be allowed to be offered into the RPM 
Auctions.   
For the RBP, there is already a separate and rigorous gating criteria that is detailed 
above, see supra Part III.C.8.e, to provide reasonable confidence that a resource committed 
through the RBP would be deliverable by the relevant Delivery Year.  Additionally, to 
avoid double procurement of capacity, the committed RBP UCAP MW must be offered 
into the corresponding RPM Auctions as price takers.  However, because not all projects 
that receive an RBP commitment may have reached Decision Point I or Decision Point II 
at the time of the relevant RPM Auctions, they may not currently be eligible to be offered 
into the RPM Auctions based on the existing definition of Planned Generation Capacity 
Resource.  As a result, PJM proposes to amend the existing definition of Planned 
Generation Capacity Resource so that any generation resource that is committed in the RBP 
would qualify as a Planned Generation Capacity Resource and be allowed to be offered 
into the relevant RPM Auctions.311 
 
311 See proposed RAA, Article 1, Definitions – Planned Generation Capacity Resource.  The clean version of 
the definition for Planned Generation Capacity Resource on which PJM is proposing revisions is the version 
the Commission accepted in Docket No. ER24-2398-000.  Since that version was accepted there have been 
overlapping versions of RAA, Article 1, Definitions that did not carry forward changes accepted in that 
docket.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 127 
 
 
 
3. 
Notice of intent (Tariff, Attachment DD, section 5.5) 
Under the current rules, any Planned Generation Capacity Resource is eligible to 
be offered into the RPM Auctions only if it is the subject of a notice of intent to be offered 
into the relevant auction.  The reason for this requirement is to provide certainty that a 
Planned Generation Capacity Resource, which does not have a capacity must-offer 
obligation, will be offered into the RPM Auction before it is included in the planning 
model.  Otherwise, inclusion of Planned Generation Capacity Resources in the planning 
models could result in an inaccurate CETL and CETO that is calculated for each locational 
deliverability area.  Because a committed RBP Resource, including any Planned 
Generation Capacity Resource, would be required to be offered into the RPM Auctions, 
imposing the requirement for unit owners to submit the same notice of intent to offer into 
the RPM Auctions would be superfluous and present a barrier for the resource to be offered 
into the RPM Auction if the unit owner missed the deadline to submit the notice of intent 
to offer.  Therefore, PJM proposes to specify that a notice of intent to offer is not required 
for any committed RBP Resource since those resources will be required to be offered into 
the RPM Auctions that correspond with the Delivery Year that such resource has an RBP 
commitment.312   
The only exception to this general rule is that for a Planned Generation Capacity 
Resource that is committed as an RBP Resource and that was not the subject of a notice of 
intent to offer for the BRA associated with the 2029/2030 Delivery Year, such Planned 
Generation Capacity Resource must be offered into the Second Incremental Auction for 
 
312 Proposed Tariff, Attachment DD, section 5.5(b).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 128 
 
 
 
the 2029/2030 Delivery Year.313  The reason for this limited exception is because PJM 
would not have included such a Planned Generation Capacity Resource in the planning 
parameters for the 2029/2030 BRA so the CETO/CETL may be inaccurately represented 
if such resource were to be offered into the 2029/2030 BRA.  Thus, a committed RBP 
Resource that is a Planned Generation Capacity Resource and happened to have already 
submitted a notice of intent to offer into the 2029/2030 BRA would still be required to be 
offered into the 2029/2030 BRA since PJM would have included such resource in the 
planning parameters.  For all other future RPM Auctions, including the 2029/2030 Second 
Incremental Auction, PJM will automatically include any committed RBP Resource in the 
planning models so a notice of intent to offer would not be necessary.  
In the event a committed RBP Resource is not expected to be in-service or 
deliverable by the relevant Delivery Year, the unit owner of such resource is required to 
notify PJM, and provide supporting documentation, that the resource is not expected to be 
deliverable no later than December 1 proceeding a BRA or 90 days prior to the 
commencement of an Incremental Auction.  Providing such notification by these deadlines, 
which are the same as the deadlines for Planned Generation Capacity Resources that are 
not committed through RBP to provide notices of intent to offer into the RPM Auctions, is 
appropriate because it would provide sufficient time for PJM to exclude from the planning 
models any committed RBP Resource that would no longer be expected to be deliverable 
by the first Delivery Year.  This is necessary so that PJM does not include a resource in the 
 
313 Id.  The First Incremental Auction for the 2029/2030 Delivery Year was canceled due to the compressed 
auction schedule, so the Second Incremental Auction is the next auction following the BRA for the 2029/2030 
Delivery Year.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 129 
 
 
 
planning parameters that will not be in service and available to provide capacity by the 
relevant Delivery Year.  Of course, a committed RBP Resource would still be subject to 
the RBP shortfall charge as discussed above, see supra Part III.C.9, should it submit a 
notice to PJM that it would not be expected to be in service by the relevant Delivery Year.  
In this way, the RBP shortfall charge acts as a financial disincentive against falsely 
notifying PJM that a resource may not be deliverable to avoid the must-offer obligation 
into the RPM Auctions.  
4. 
Minimum Offer Price Rule (proposed Tariff, Attachment DD, 
section 5.14(h-2)) 
Given that any committed RBP Resource is required to be offered into the RPM 
Auctions as a price taker for the term of the RBP commitment, such resource must be 
offered into the RPM Auction at $0/MW-day.  To ensure that this requirement is not 
frustrated by the existing Minimum Offer Price Rule, PJM is proposing to exempt, only for 
committed RBP Resources, the requirement that a Capacity Market Seller provide a 
certification that the underlying resource is not receiving or expected to receive 
Conditioned State Support and that the Capacity Market Seller does not intend to submit a 
Sell Offer to exercise buyer-side market power.314  Additionally, the proposed Tariff also 
clarifies that for committed RBP Resources, the lack of such a certification would not 
subject the underlying resource to the Minimum Offer Floor Price.315  These updates will 
ensure that a committed RBP Resource will be allowed to be offered into the RPM Auction 
as a price taker without violating the Minimum Offer Price Rule.  Finally, there is no 
 
314 Proposed Tariff, Attachment DD, section 5.14(h-2)(1)(A). 
315 Proposed Tariff, Attachment DD, section 5.14(h-2)(1)(B)(i).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 130 
 
 
 
concern of a potential exercise of buyer-side market power for committed RBP Resources 
because such resources are being procured by PJM through the RBP for resource adequacy 
purposes and are required to be offered as price takers to avoid double procurement of 
capacity. 
IV. 
CORRESPONDENCE 
The following individuals are designated for inclusion on the official service list in this 
proceeding and for receipt of any communications regarding this filing: 
Craig Glazer 
Vice President–Federal Government Policy 
PJM Interconnection, L.L.C. 
1200 G Street, N.W., Suite 600 
Washington, D.C. 20005 
(202) 423-4743  
craig.glazer@pjm.com 
 
Ryan J. Collins 
Vivian W. Chum 
Wright & Talisman, P.C. 
1200 G Street, N.W., Suite 600 
Washington, D.C. 20005 
(202) 393-1200  
collins@wrightlaw.com 
chum@wrightlaw.com 
Chenchao Lu 
Associate General Counsel 
PJM Interconnection, L.L.C. 
2750 Monroe Blvd. 
Audubon, PA  19403 
(610) 666-2255  
chenchao.lu@pjm.com 
 
 
V. 
REQUESTED EFFECTIVE DATE AND CONSENT TO MODIFICATION 
OR SEVERANCE OF ISSUES 
PJM requests that the Commission issue an order on this filing and make this 
proposal effective by no later than September 29, 2026, which is 60 days after the date of 
this filing.  Commission action and an effective date of no later than September 29, 2026, 
will allow PJM to commence the RBP immediately thereafter.  Upon Commission 
acceptance of this filing without modification, PJM intends to commence the RBP on 
September 30, 2026.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 131 
 
 
 
As noted above, however, 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 the FPA and NRG Power Marketing,316 where such modification is consistent with 
PJM’s overarching objectives in this filing.317  Should the Commission require 
modifications to the proposed RBP as detailed in this filing, PJM may need to delay the 
commencement of the RBP beyond September 30, 2026, to implement the RBP consistent 
with such Commission directed changes.  In addition, PJM provides the following requests 
and observations:     
First, should the Commission exercise its authority to modify the proposed Tariff 
language herein pursuant to the FPA and NRG Power Marketing, PJM respectfully requests 
that the Commission expressly prescribe the revised rate or rule in its order.  Prescriptive 
revised language from the Commission would provide the “necessary predictability” to 
allow PJM to implement such changes to the RBP in a timely manner.318  PJM’s submittal 
 
316 NRG Power Mktg., 862 F.3d at 108.  As the Commission has repeatedly stated, “[t]he United States Court 
of Appeals for the District of Columbia Circuit has held that, in certain circumstances, the Commission has 
‘authority to propose modifications to a utility’s [FPA section 205] proposal if the utility consents to the 
modifications.’”  N.Y. Indep. Sys. Operator, 188 FERC ¶ 61,051 at P 22 n.36 (alteration in original) (citing 
NRG Power Mktg., 862 F.3d at 114-15); see Midcontinent Indep. Sys. Operator, 180 FERC ¶ 61,141 at P 26 
n.29 (same); ISO New England, 175 FERC ¶ 61,172 at P 16 n.20 (same). 
317 PJM is not, for example, suggesting that the Commission may modify or sever provisions of its proposal 
to result in an “entirely different rate design.”  NRG Power Mktg., 862 F.3d at 115 (“Our decisions in City of 
Winnfield and Western Resources indicate that Section 205 does not allow FERC to suggest modifications 
that result in an ‘entirely different rate design’ than the utility’s original proposal or the utility’s prior rate 
scheme.”); see also id. at 116 (holding that the Commission’s modifications resulted in an entirely different 
rate design where Commission’s modifications: (1) replaced PJM’s proposal to permit exemption where 
generators demonstrate on a case-by-case basis that their costs fell below the price floor with one in which 
generators can claim exemptions even if they cannot demonstrate that their price falls below the floor; (2) 
undid the compromise between LSEs and Generators and thus “eviscerated the terms of the bargain.”). 
318 PJM Interconnection, 175 FERC ¶ 61,137 at P 110 (first quoting Aera Energy LLC, 789 F.3d at 190-92 
“affirming the Commission, finding ‘FERC’s conditional acceptance . . . simply required Kern River to 
substitute one number for another when allocating costs to the rolled-in shippers.  . . . Because this mechanical

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 132 
 
 
 
of any compliance filing implementing such modifications would constitute PJM’s consent 
and acceptance of the Commission’s modifications.   
Second, PJM observes that the facts underlying the PJM proposal at issue in NRG 
Power Marketing are distinguishable from the facts here.  In NRG Power Marketing, the 
FPA section 205 filing with the Commission was one in which “PJM asked the 
Commission ‘to view this filing, not as a list of discrete Tariff changes, but . . . a hard-
fought compromise package, and to approve it as such.’”319  By contrast, the proposal put 
forth here is not a stakeholder compromise package.  Unlike NRG Power Marketing, there 
is no danger of undoing the compromise between LSEs and Generators and thus 
“eviscerat[ing] the terms of the bargain.”320  Rather, this filing is the product of an RBP 
proposal that was independently endorsed by the PJM Board following the CIFP 
stakeholder process.  Moreover, through this pre-emptive grant of authority pursuant to 
which the Commission may sever and modify each element of the proposal, stakeholders 
are on notice of potential changes to the proposal as filed, and will have the opportunity to 
comment as they feel necessary and appropriate.   
 
change gave Kern River no discretion to adjust its rate models, FERC provided sufficient notice to 
ratepayers,’” and then quoting Elec. Dist. No. 1, 774 F.2d at 493 “vacating when the ‘effective date of an 
order set[] forth no more than the basic principles pursuant to which the new rates are to be calculated’” 
(alteration in original)).  As the Commission elaborated further in PJM Interconnection, 175 FERC ¶ 61,137 
at P 110, mere “direction” without “sufficient detail on each element [of the replacement rate] that 
[customers/market participants] could determine when their transactions would be subject to [the new rule],” 
would mean that implementation of the compliance directive prior Commission approval would violate the 
filed rate doctrine.  PJM Interconnection, 175 FERC ¶ 61,137 at P 110 (quoting Elec. Dist. No. 1, 774 F.2d 
at 493 “[P]urchasers of electricity cannot plan their activities unless they know the cost of what they are 
receiving, ‘providing the necessary predictability is the whole purpose of the well-established filed rate 
doctrine.’” (citing Ark. La. Gas Co., 453 U.S. at 577)). 
319 NRG Power Mktg., 862 F.3d at 113. 
320 Id. at 116.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 133 
 
 
 
Third, although PJM consents to make each element of the proposed revisions to 
the Tariff and RAA severable, PJM has demonstrated that each element of its proposal is 
just and reasonable.  Notwithstanding PJM’s grant of authority to sever, PJM urges the 
Commission to accept all revisions as proposed so that the RBP can commence on 
September 30, 2026.   
To the extent the Commission does sever and modify any element, the Commission 
should take care to ensure that its replacement rate appropriately meshes with the other 
interlocking parts of the RBP framework to allow for quick and efficient implementation.  
The PJM Board has extensively considered the requirements to implement the RBP that 
account for risks associated with a fixed, 15-year term of procurement, including risk of 
Transmission Owner exit, and coordination with states.  In addition, severance of specific 
elements of the proposal without a prescriptive replacement rate would not provide the 
sufficient detail necessary to promptly implement RBP.  Finally, modifications to this filing 
could jeopardize the commencement of the RBP in September 2026, which would also 
have downstream impacts given that the BRA for the 2029/2030 Delivery Year is currently 
scheduled to commence on December 9, 2026. 
VI. 
DOCUMENTS ENCLOSED 
This filing consists of the following: 
1. 
This transmittal letter;  
2. 
Revisions to the PJM Tariff (in redlined and non-redlined format (as 
Attachments A and B, respectively) and in electronic tariff filing format as 
required by Order No. 714);321  
 
321 Electronic Tariff Filings, Order No. 714, 124 FERC ¶ 61,270 (2008), final rule, Order No. 714-A, 147 
FERC ¶ 61,115 (2014).

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 134 
 
 
 
3. 
Affidavit of Ms. Danielle Croop, Senior Manager in the Market Design group 
of PJM Interconnection, L.L.C. as Attachment C; and 
4. 
Affidavit of Ms. Gwen Kelly, Senior Director in Credit Risk and Collateral 
Management of PJM Interconnection, L.L.C. as Attachment D. 
VII. 
SERVICE 
PJM has served a copy of this filing on all PJM members and on all state utility 
regulatory commissions in the PJM Region by posting this filing electronically.  In 
accordance with the Commission’s regulations,322 PJM will post a copy of this filing to the 
Commission filings section of its internet site, located at the following link:  
https://www.pjm.com/library/filing-order.aspx with a specific link to the newly filed 
document, and will send an e-mail on the same date as this filing to all PJM members and 
all state utility regulatory commissions in the PJM Region323 alerting them that this filing 
has been made by PJM and is available by following such link.  PJM also serves the parties 
listed on the Commission’s official service list for this docket.  If the document is not 
immediately available by using the referenced link, the document will be available through 
the referenced link within 24 hours of the filing.  Also, a copy of this filing will be available 
on 
the 
Commission’s 
eLibrary 
website 
located 
at 
the 
following 
link:  
http://www.ferc.gov/docs-filing/elibrary.asp in accordance with the Commission’s 
regulations and Order No. 714. 
 
322 See 18 C.F.R. §§ 35.2(e), 385.2010(f)(3). 
323 PJM already maintains, updates and regularly uses e-mail lists for all PJM members and affected state 
commissions.

Honorable Debbie-Anne A. Reese 
July 31, 2026 
Page 135 
 
 
 
VIII. CONCLUSION 
Based on the foregoing, PJM requests that the Commission accept the enclosed 
Tariff and RAA revisions by September 29, 2026, at the latest, effective September 29, 
2026. 
Respectfully submitted, 
/s/ Vivian W. Chum 
 
Craig Glazer 
Vice President–Federal Government Policy 
PJM Interconnection, L.L.C. 
1200 G Street, N.W., Suite 600 
Washington, D.C.  20005 
(202) 423-4743  
craig.glazer@pjm.com 
 
Ryan J. Collins 
Vivian W. Chum 
Wright & Talisman, P.C. 
1200 G Street, N.W., Suite 600 
Washington, D.C.  20005 
(202) 393-1200  
collins@wrightlaw.com 
chum@wrightlaw.com 
 
Chenchao Lu 
Associate General Counsel 
PJM Interconnection, L.L.C. 
2750 Monroe Blvd. 
Audubon, PA  19403 
(610) 666-2255  
chenchao.lu@pjm.com 
 
 
 
July 31, 2026