EL27-11-000 · 2026-11-03 · Exelon

Complaint Requesting Fast Track Processing of Exelon Corporation (prompt capacity auction from the 2030/31 Delivery Year)

UNITED STATES OF AMERICA 
BEFORE THE 
FEDERAL ENERGY REGULATORY COMMISSION 
Exelon Corporation, 
) 
 
 
) 
 
Complainant 
) 
 
 
) 
 
v. 
) 
Docket No. EL27-___-000 
 
) 
 
PJM Interconnection, L.L.C., 
) 
 
 
) 
 
Respondent 
) 
 
 
) 
 
 
COMPLAINT REQUESTING FAST TRACK PROCESSING OF  
EXELON CORPORATION 
/s/ Jordan Kwok 
/s/ Thomas S. DeVita 
Jordan Kwok 
Thomas S. DeVita 
Director, Federal Regulatory Affairs 
Kimberly B. Frank 
Exelon Corporation 
Stuart B. Robbins 
701 Ninth Street, N.W. 
K&L Gates LLP 
Washington, D.C. 20068 
1601 K Street, NW 
(667) 313-0421 
Washington, DC  20006 
jordan.kwok@exeloncorp.com 
(202) 778-9000 
 
thomas.devita@klgates.com 
/s/ Alejandro Bautista 
kimberly.frank@klgates.com 
Alejandro Bautista 
stuart.robbins@klgates.com 
Assistant General Counsel 
 
Exelon Corporation 
Counsel for Exelon Corporation  
2301 Market Street 
 
Philadelphia, PA 19101 
 
(267) 533-0120 
 
alejandro.bautista@exeloncorp.com 
 
 
 
 
Dated: November 3, 2026

Table of Contents 
 
 
-i- 
 
 
I. 
INTRODUCTION .................................................................................................... 3 
II. 
PARTIES AND COMMUNICATIONS................................................................. 10 
A. 
Complainant Exelon.................................................................................... 10 
B. 
Respondent PJM ......................................................................................... 11 
C. 
Communications ......................................................................................... 11 
III. 
BACKGROUND .................................................................................................... 12 
IV. 
LEGAL ARGUMENT ............................................................................................ 14 
A. 
The Current Three-Year Forward Period of RPM is No Longer Just and 
Reasonable. ................................................................................................. 14 
i. 
The risk balancing analysis the Commission relied on in 2006 to 
accept the load forecast inaccuracies inherent in RPM’s multi-year 
forward period has fundamentally collapsed in 2026. .................... 14 
a. 
Evidence that PJM Load Forecast Inaccuracies Have 
Increased Since 2006. ......................................................... 16 
b. 
Evidence that Capacity Resources cannot be constructed in 
the PJM Region within the current three-year cycle. .......... 21 
ii. 
The prospective assumptions in 2006 regarding the ability of RPM’s 
multi-year forward period to incentivize LSE bilateral contracting 
and risk hedging have been disproven over the course of 20 years.
......................................................................................................... 25 
iii. 
The current three-year forward period inhibits efficient resource exit 
and Deactivation, as it requires generation owners to invest in the 
absence of reasonable predictability in future operational capability 
and environmental policy. ............................................................... 30 
a. 
Operational Uncertainties ................................................... 32 
b. 
Environmental Policy Uncertainties ................................... 33 
iv. 
PJM’s current capacity accreditation methodology (ELCC) bears no 
resemblance to the eFORd model considered by the Commission in 
2006, and the three-year forward period forces PJM to integrate 
speculative assumptions into its ELCC modeling. ......................... 40 
v. 
The current three-year forward period undermines the accuracy of 
other BRA planning parameters, including the assumed resource mix 
in each Locational Deliverability Area used to calculate 
CETO/CETL values, leading to unjust and unreasonable results. .. 44 
B. 
The Commission Should Adopt a Prompt Auction Schedule as the Just and 
Reasonable Replacement Rate. ................................................................... 46 
i. 
A prompt auction will significantly improve the accuracy of key 
BRA auction parameters, resulting in capacity prices that better

-ii- 
 
 
reflect actual supply and demand fundamentals and system 
conditions in the Delivery Year. ..................................................... 47 
ii. 
A prompt auction will significantly enhance the quality of 
information and the accuracy of the price signal used in generator 
Deactivation decisions. ................................................................... 49 
iii. 
A prompt auction schedule will significantly enhance the quality of 
data used in PJM’s ELCC capacity accreditation, thereby better 
aligning both price and payments with resource contributions to 
resource adequacy. .......................................................................... 51 
iv. 
A prompt auction will significantly reduce the risks to new resources 
seeking to enter the market by creating more certainty regarding their 
expected availability for the Delivery Year. ................................... 53 
V. 
REFUND EFFECTIVE DATE ............................................................................... 54 
VI. 
RULE 206 REQUIREMENTS ............................................................................... 54 
A. 
Good faith estimate of financial impact or harm (Rule 206(b)(4)) ............. 54 
B. 
Practical, operational, or nonfinancial impacts (Rule 206(b)(5)) ............... 54 
C. 
Whether the matters are pending in any other FERC proceeding or other 
forum (Rule 206(b)(6)) ............................................................................... 54 
D. 
Specific relief or remedy requested (Rule 206(b)(7)) ................................. 55 
E. 
Documents supporting the complaint (Rule 206(b)(8)) .............................. 55 
F. 
Use of alternative dispute resolution (Rule 206(b)(9)) ............................... 55 
G. 
Notice (Rule 206(b)(10)) ............................................................................ 55 
H. 
Request for Fast Track Processing (Rule 206(b)(11)) ................................ 55 
VII. 
SERVICE AND NOTICE....................................................................................... 56 
VIII. 
CONCLUSION ....................................................................................................... 56

UNITED STATES OF AMERICA 
BEFORE THE 
FEDERAL ENERGY REGULATORY COMMISSION 
Exelon Corporation, 
) 
 
 
) 
 
Complainant 
) 
 
 
) 
 
v. 
) 
Docket No. EL27-___-000 
 
) 
 
PJM Interconnection, L.L.C., 
) 
 
 
) 
 
Respondent 
) 
 
 
) 
 
 
COMPLAINT REQUESTING FAST TRACK PROCESSING OF  
EXELON CORPORATION  
Pursuant to sections 206, 306, and 309 of the Federal Power Act (“FPA”),1 and Rule 
206 of the Federal Energy Regulatory Commission’s (“FERC” or the “Commission”) Rules of 
Practice and Procedure,2 Exelon Corporation (“Exelon”) hereby submits this complaint against 
PJM Interconnection, L.L.C. (“PJM”).  For the reasons stated herein and in the attached 
Affidavits of Dr. Emma Nicholson and Deborah Sears,3 Exelon respectfully requests that the 
Commission: (i) find under FPA section 206 that the current three-year forward period of 
PJM’s Reliability Pricing Model4 (“RPM”) is no longer just and reasonable; and (ii) adopt as 
 
1 16 U.S.C. §§ 824e, 825e, 825h.   
2 18 C.F.R. § 385.206.   
3 The Nicholson Affidavit is included as Attachment A to this complaint, and the Sears Affidavit is included as 
Attachment B. 
4 Terms not otherwise defined herein shall have the same meaning as in the PJM Open Access Transmission 
Tariff (“Tariff”), the Amended and Restated Operating Agreement of PJM Interconnection, L.L.C. (“Operating 
Agreement”), and the Reliability Assurance Agreement Among Load Serving Entities in the PJM Region 
(“RAA”).  The Tariff, Operating Agreement, and RAA are currently located under PJM’s “Intra-PJM Tariffs” 
eTariff Title, available here: https://etariff.ferc.gov/TariffBrowser.aspx?tid=1731.

2 
the just and reasonable replacement rate a “prompt” auction schedule, to run two months5 
before a given Delivery Year, starting with the 2030/2031 Delivery Year and continuing 
beyond.6   
Exelon respectfully requests that the Commission establish a refund effective date of 
January 1, 2027, and permit Fast Track processing under Rule 206(h) to facilitate a 
Commission order by no later than January 31, 2027—currently the last day before the 
scheduled posting date of the planning parameters for the 2030/31 Delivery Year Base 
Residual Auction (“BRA”).  To be clear, nothing in this complaint is intended to apply to, or 
otherwise disrupt the implementation of, the 2029/2030 Delivery Year BRA, which is 
scheduled to run in December 2026, nor any Reliability Backstop Procurement (“RBP”)7 
auction.8   
Granting the relief requested herein will have three important outcomes.  First, it will 
remedy an unjust and unreasonable aspect of RPM (the three-year forward period) by better 
aligning the parameters used in each BRA with actual system conditions, resulting in an 
auction that relies on more accurate load forecasts, resource availability data, and capacity 
accreditation, and that facilitates more efficient resource entry and exit through improved 
 
5 As discussed herein, Exelon acknowledges that the Commission has wide legal discretion under FPA section 
206 in establishing the just and reasonable replacement rate, but recommends two months as a reasonable period 
between when PJM publishes its load forecast information in late January and the start of the Delivery Year on 
June 1.  Two months also provides time for pre-auction activities to take place following the publication of the 
load forecast in January, gives Market Participants and PJM sufficient notice of the applicable auction parameters, 
and provides supply resources more than one month to make final operating arrangements if they clear the auction.   
6 Exelon acknowledges that conforming changes to other PJM Governing Agreements may be needed, should the 
Commission grant the relief requested herein. 
7 See generally Docket Nos. ER26-3380-000, EL26-108-000. 
8 Out of an abundance of caution, Exelon is not proposing to apply the “prompt” auction remedy sought herein to 
the 2029/2030 Delivery Year BRA, in light of the fact that the applicable planning parameters for the 2029/2030 
Delivery Year BRA have already been posted.  See PJM Power Providers Group v. FERC, 96 F.4th 390 (3d Cir. 
2024).

3 
market signals.9  Second, it will functionally push out the date of the BRA for the 2030/31 
Delivery Year, currently scheduled for May 2027, to approximately March 2030, thereby 
preventing Exelon’s customers, and PJM customers at large, from being exposed to the 
uncapped surge in capacity prices expected this coming spring under the current three-year 
forward RPM period while there is significant uncertainty about supply and demand 
fundamentals and PJM’s resource adequacy structure over this time horizon.  Third, it will 
provide PJM and its stakeholder community, operating under the Commission’s oversight, 
critical time to develop—and timely transition to—the comprehensive resource adequacy 
reforms that the Trump Administration, PJM Governors, and PJM itself recognize are critical 
to ensuring a long-term, enduring, and just and reasonable capacity construct in the PJM 
Region.10 
I. 
INTRODUCTION 
Customers are, and always have been, at the center of Exelon’s core mission and values.   
Exelon is committed to addressing the mounting affordability pressures experienced every day 
by its more than 10.7 million customers in the PJM Region.11  In furtherance of this 
 
9 See Nicholson Affidavit, at ¶¶ 54-59. 
10 See, e.g., Statement of Principles Regarding PJM (Jan. 16, 2026) (hereafter, the “Statement of Principles”) 
(“PJM should immediately embark on a stakeholder process to reform the capacity market to ensure long-term 
viability and prevent consumers from bearing excessive ongoing costs, with the expectation that these reforms be 
implemented in time for the BRA currently scheduled for May 2027.”); Powering Reliability Through Market 
Design at 4 (May 6, 2026) (hereafter, the “PJM White Paper”) (“On Jan. 16, 2026, the PJM Board of Managers 
directed PJM staff to undertake a holistic review of the capacity market design and investment incentives. The 
Board recognized that the market’s current price volatility—while economically rational—is placing 
unsustainable stress on the governmental compact that allows the market to function, and that the foundational 
assumptions of the Reliability Pricing Model design must be reexamined in a resource-constrained world.  This 
white paper is PJM’s response to that directive.”).  The Statement of Principles is available here: 
https://www.energy.gov/documents/statement-principles-regarding-pjm.  The PJM White Paper is available here: 
https://www.pjm.com/-/media/DotCom/library/reports-notices/special-reports/2026/20260506-powering-
reliability-through-market-design.pdf.  
11 More information about the Exelon Promise is available here: https://www.exeloncorp.com/company/exelon-
promise.

4 
commitment, Exelon submits this complaint against the RPM three-year forward period, to 
ensure the people and businesses it serves, and the customers of the PJM Region more broadly, 
receive what they are entitled to—market outcomes predicated on accurate information. 
The auction schedule of RPM that has successfully driven efficient outcomes for 
Exelon customers in the past has proven incapable of meeting the needs of the PJM Region 
today and into the future.  Customers in all six Exelon service territories are directly impacted 
by the extraordinary prices produced by RPM in recent years, beginning with the 2025/2026 
Delivery Year BRA that cleared at several multiples of the historical average capacity price in 
PJM, and at roughly ten times the prior year’s clearing price.12  The crisis has only deepened 
since then, with the 2027/2028 and 2028/2029 Delivery Year BRAs clearing at the temporary 
Commission-approved price cap and simultaneously falling thousands of MWs short of PJM’s 
target Installed Reserve Margin.13  While PJM’s staff, management, and Board of Managers 
(“Board”) have diligently and competently administered RPM Auctions over the last two 
decades, it is self-evident that RPM in its current structure is fundamentally broken.  Not only 
are PJM customers at large being forced to pay unprecedented prices for capacity, they are not 
getting sufficient capacity in return, and are paying for a widening gap between supply and 
demand as a reliability deficit looms.   
As the Commission correctly observed on September 30, 2026, “[w]e think it clear that 
PJM’s ordinary instrument for procuring sufficient capacity to meet PJM’s reliability 
requirement, the RPM, has failed to keep pace with the unprecedented influx of large load into 
 
12 See, e.g., PJM Capacity Prices Spike 10-Fold in 2025/2026 Auction, RTO Insider, Devin Leith-Yessian (Jul. 
30, 2024),  https://www.rtoinsider.com/84356-pjm-capacity-prices-spike-2025-26-auction/.   
13 PJM’s 2027/2028 BRA report is available here: https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-
auction-info/2027-2028/2027-2028-bra-report.pdf.  PJM’s 2028/2029 BRA report is available here: 
https://www.pjm.com/-/media/DotCom/markets-ops/rpm/rpm-auction-info/2028-2029/2028-2029-bra-results-
report.pdf.

5 
the PJM Region in recent years.”14  Exelon agrees with the Commission’s assessment and is 
taking action.  In this complaint, Exelon demonstrates that an integral component of RPM—
the three-year forward period—is no longer just and reasonable, because it produces market 
outcomes that charge customers on the basis of parameters estimated four years in advance of 
delivery completion, thereby structuralizing uncertainty and inaccuracy with no proportional 
benefit.  While Exelon, like other PJM Transmission Owners and PJM itself, has taken steps 
to proactively enhance the accuracy of its own load forecast and to eliminate speculative 
demand (including through its pioneering use of Transmission Security Agreements 
(“TSAs”)),15 it is still fundamentally bound by RPM’s mandate to predict reality years in 
advance—a challenge exacerbated by the distinct nature, characteristics, and volatile 
development schedules of today’s large loads, as well as the changing nature of market 
dynamics and federal, state, and local environmental, permitting, and tax policies.    
The market outcomes produced under this paradigm create an unjustifiable chasm 
between the costs customers pay and the capacity they receive, while simultaneously failing to 
accurately portray the underlying supply and demand dynamics of the PJM Region in a manner 
that inhibits efficient resource exit, and fails to incentivize efficient resource entry.  
Accordingly, Exelon respectfully requests the Commission exercise its authority under FPA 
section 206 to find the existing three-year forward period of RPM unjust and unreasonable, 
and direct PJM to establish a just and reasonable “prompt” auction schedule, to run two months 
before a given Delivery Year, starting with the 2030/2031 Delivery Year and continuing 
 
14 PJM Interconnection, L.L.C., 196 FERC ¶ 61,245, at P 29 (2026). 
15 A TSA is a customer protection mechanism that requires large new power users like data centers to make firm 
financial commitments for the transmission service that the grid must be ready to provide.  More information 
about TSAs is available here: https://www.exeloncorp.com/grid/exelons-transmission-security-agreements-a-
pioneering-model-for-customer-protection1

6 
beyond.  Exelon acknowledges that the Commission has wide legal discretion under FPA 
section 206 in establishing the just and reasonable replacement rate,16 but recommends two 
months as a reasonable period between when PJM publishes its load forecast information in 
late January and the start of the Delivery Year on June 1.  Two months also provides time for 
pre-auction activities to take place following the publication of the load forecast in January, 
gives Market Participants and PJM sufficient notice of the applicable auction parameters, and 
provides Capacity Resource owners more than one month to make final operating 
arrangements if they clear the auction.   
While this particular complaint is narrowly focused on the three-year forward period 
of RPM, and the prompt auction remedy proposed herein is just and reasonable on its own, 
Exelon acknowledges the targeted surgery requested in this complaint will not heal all that ails 
RPM.  Developments in recent years have exposed broad structural shortcomings inherent in 
the PJM resource adequacy paradigm and capacity market framework that have led to the crisis 
the PJM Region faces today.  These include (i) the explosive growth of data center load, (ii) a 
historic procurement crisis for components essential to the development of new capacity, (iii) 
challenges in the permitting and financing of new generation, (iv) frequent market rule 
changes, and (v) reactive interventions aimed at promoting just, reasonable, and affordable 
rates for customers.  There is accordingly a considerable amount of work still to be completed 
by PJM and its stakeholder community to identify a more durable resource adequacy construct 
that can reliably support the efficient entry and exit of Capacity Resources from the PJM 
 
16 See, e.g., Niagara Mohawk Power Corp. v. FPC, 379 F.2d 153, 159 (D.C. Cir. 1967) (“[T]he breadth of agency 
discretion is, if anything, at zenith when the action assailed relates primarily . . . to the fashioning of policies, 
remedies and sanctions . . . in order to arrive at maximum effectuation of Congressional objectives.”).

7 
Region, while simultaneously protecting consumers from the extreme price and reliability 
outcomes that have become the unjust and unreasonable norm. 
In the interim, through this complaint, Exelon is providing the Commission with a legal 
pathway and evidentiary record to immediately address one significant defect of RPM (the 
three-year forward period), and in doing so ensure both customers and suppliers in the PJM 
Region benefit from an auction schedule that better reflects actual supply and demand 
fundamentals, and sends more accurate investment signals.  Such action directly aligns with 
the Commission’s core responsibilities under the FPA, as the Commission’s “first and foremost 
duty” under the statute is “to protect consumers from unjust and unreasonable rates,”17 and the 
Commission has long viewed efficient, accurate, and competitive markets as a vehicle to 
achieve that end.18  As an ancillary but not insignificant benefit, granting the instant complaint 
would provide much-needed time for PJM, States, and the PJM stakeholder community to 
thoughtfully develop comprehensive and durable reforms to the capacity construct in the PJM 
Region and submit a proposal to the Commission, without the unnecessary specter of extreme 
 
17 Morgan Stanley Cap. Grp. Inc. v. Pub. Util. Dist. No. 1 of Snohomish Cnty., 554 U.S. 527, 551 (2008) 
(quotations and citations omitted). See also Atl. Refin. Co. v. Pub. Serv. Comm’n of N.Y., 360 U.S. 378, 388 (1959) 
(The FPA’s sister, the Natural Gas Act, was “framed as to afford consumers a complete, permanent and effective 
bond of protection from excessive rates and charges.”); NAACP v. FPC, 520 F.2d 432, 438 (D.C. Cir. 1975) (“The 
Commission’s primary task . . . is to guard the consumer from exploitation . . . .”), aff’d, 425 U.S. 662 (1976).   
18 See Fed. Energy Regulatory Comm’n v. Elec. Power Supply Ass’n, 577 U.S. 260, 267-68 (2016) [hereinafter 
FERC v. EPSA] (“The Commission instead undertakes to ensure ‘just and reasonable’ wholesale rates by 
enhancing competition—attempting, as we recently explained, ‘to break down regulatory and economic barriers 
that hinder a free market in wholesale electricity.’”) (citing Morgan Stanley Capital Group Inc. v. Public Util. 
Dist. No. 1 of Snohomish Cty., 554 U.S. 527, 536 (2008)); Public Citizen, Inc. v. FERC, 7 F.4th 1177, 1194 (D.C. 
Cir. 2021) (explaining that “the whole premise of the Commission’s market-based system is that a properly 
competitive market will necessarily produce just and reasonable prices,” and that the Commission satisfies its 
statutory obligations by ensuring that markets are fair, competitive, and unmanipulated); Calpine Corp. et. al., 
171 FERC ¶ 61035, at P 139 (2020) (upholding determination on rehearing that the relevant replacement rate will 
enable PJM’s capacity market to send price signals on which both investors and consumers can rely to guide the 
entry and exit of economically-efficient capacity resources, will support the capacity market’s ability to attract 
investments, and “supports the capacity market’s core objective of maintaining resource adequacy at just and 
reasonable rates, particularly during periods when entry is needed.”); Wholesale Competition in Regions with 
Organized Electric Markets , Order No. 719, 125 FERC ¶ 61,071, at P 13 (tying reforms to wholesale competition 
to its responsibilities under FPA §§ 205 and 206).

8 
pricing outcomes with each passing BRA.  Additionally, remedying this defect by moving to 
a prompt auction schedule now, while this broader market redesign takes place, will have 
several immediate benefits for the PJM Region: 
• It will allow the PJM Region to transition more quickly to the new resource 
adequacy structure once such a construct is ultimately established.  Maintaining the 
three-year forward period would push the completion of any transition ahead to, at 
best, four years (the current forward period plus the Delivery Year) after those 
reforms are accepted.  In the current fast-moving energy environment, that is simply 
too long, and customers should not be expected to keep taking on long-term 
commitments to this current broken model. 
• Similarly, it will allow future market reforms to “sink in” more quickly should 
future adjustments be needed.  If history is any guide, there will likely be a need, 
even after this round of reforms, to adjust rules to address lingering shortcomings.  
A prompt structure allows PJM customers to benefit from future market 
improvements more quickly than the existing three-year forward period.  
• It will relieve the challenges and administrative burden on PJM and stakeholders 
associated with constantly running and participating in Incremental Auctions 
(“IAs”). 
• It will improve alignment of participation timing for non-conventional resources 
like demand response, which are challenged by long forward commitments in the 
context of capacity obligations, and eliminate concerns regarding speculative price 
arbitrage. 
Critically, the discrete remedy sought by Exelon through this complaint is not new.  
The Commission already found prompt auction schedules to be just and reasonable in ISO-NE 
Inc. (“ISO-NE”),19 the New York Independent System Operator, Inc. (“NYISO”),20 and the 
Midcontinent Independent System Operator, Inc. (“MISO”),21 even though these three regions 
have diverse approaches to resource adequacy, ranging from utility-owned generation under 
 
19 See ISO New England Inc., 194 FERC ¶ 61,249 (2026) (“ISO-NE Order”).  
20 See New York Independent System Operator, Inc., Market Administration and Control Area Services Tariff, 
§§ 5.13, 5.14.1.1. 
21 See Midcontinent Indep. Sys. Operator, Inc., 162 FERC ¶ 61,176, at PP 70, 74 (2018) (“MISO Order”), reh’g 
denied, 170 FERC ¶ 61,215, at PP 125-26 (2020) (“MISO Rehearing Order”).

9 
state commission Integrated Resource Plans (“IRP”) to fully restructured, market-based 
frameworks.  Action by the Commission in this proceeding will align PJM’s capacity auction 
schedule with all other Regional Transmission Organizations and Independent System 
Operators (“RTOs/ISOs”) that have centralized capacity market constructs.   
Exelon presents its legal case under FPA section 206 in Part IV of this complaint, which 
is divided into two subparts.  In Part IV.A, Exelon demonstrates that the three-year forward 
period of RPM has become unjust, unreasonable, unduly discriminatory or preferential under 
FPA section 206, for the following five reasons: 
1. The risk balancing analysis the Commission relied on in 2006 to accept the load 
forecast inaccuracies inherent in RPM’s multi-year forward period has 
fundamentally collapsed in 2026.   
2. The prospective assumptions in 2006 regarding the ability of RPM’s multi-year 
forward period to incentivize Load-Serving Entity (“LSE”) bilateral contracting 
and risk hedging have been disproven over the course of 20 years. 
3. The current three-year forward period inhibits efficient resource exit and 
Deactivation, as it requires generator owners to invest in the absence of reasonable 
predictability in future operational capability and environmental policy.   
4. PJM’s current capacity accreditation methodology, Effective Load Carrying 
Capability (“ELCC”) bears no resemblance to the Equivalent Forced Outage Rate 
- demand (“eFORd”) model considered by the Commission in 2006, and the three-
year forward period forces PJM to integrate speculative assumptions into its ELCC 
modeling. 
5. The current three-year forward period undermines the accuracy of other BRA 
planning parameters, including the assumed resource mix in each Locational 
Deliverability Area (“LDA”) used to calculate Capacity Emergency Transfer 
Objective (“CETO”) and Capacity Emergency Transfer Limit (“CETL”) values, 
leading to unjust and unreasonable results.  
In Part IV.B, Exelon requests that the Commission replace the three-year forward 
period of RPM with a prompt auction, starting with the 2030/2031 Delivery Year and 
continuing beyond.  Exelon explains that a prompt auction is just and reasonable for the 
following four reasons:

10 
1. A prompt auction will significantly improve the accuracy of key BRA auction 
parameters, resulting in capacity prices that better reflect actual supply and demand 
fundamentals and system conditions in the Delivery Year. 
2. A prompt auction will significantly enhance the quality of information and the 
accuracy of the price signal used in generator Deactivation decisions.  
3. A prompt auction will significantly enhance the quality of data used in PJM’s 
ELCC capacity accreditation, thereby better aligning both price and payments with 
resource contributions to resource adequacy. 
4. A prompt auction will significantly reduce the risks to new resources seeking to 
enter the market by creating more certainty regarding their expected availability for 
the Delivery Year. 
II. 
PARTIES AND COMMUNICATIONS 
A. 
Complainant Exelon 
Exelon is one of the nation’s largest utility holding companies, providing transmission 
and distribution service to nearly 11 million customers in the PJM Region through its regulated 
subsidiaries Atlantic City Electric Company (“ACE”), Baltimore Gas and Electric Company 
(“BGE”), Commonwealth Edison Company (“ComEd”), Delmarva Power & Light Company 
(“DPL”), PECO Energy Company (“PECO”), and Potomac Electric Power Company 
(“Pepco”) (together, the “Exelon Companies”).  Exelon’s more than 20,000 employees 
dedicate their time and expertise to supporting the communities they live in and serve through 
reliable, affordable, and efficient energy delivery, workforce development, economic 
development, and volunteerism.  
The Exelon Companies are public utilities under the FPA, and signatories to both the 
PJM Consolidated Transmission Owners Agreement (“CTOA”) in their capacity as PJM 
Transmission Owners, and the RAA in their capacity as PJM LSEs.

11 
B. 
Respondent PJM 
PJM is the nation’s largest RTO, coordinating the movement of wholesale electricity 
in all or parts of 13 states and the District of Columbia.22  As an RTO, PJM is responsible for 
the reliability of the high-voltage transmission system serving 68 million people in all or parts 
of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, 
Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.  PJM 
also administers the PJM wholesale electricity markets, including the Day-ahead Energy 
Market, the Real-time Energy Market, ancillary services markets, and, as relevant here, the 
RPM. 
C. 
Communications  
All correspondence and communications to Exelon in this docket should be addressed 
to the following individuals, whose names should be entered on the official service list 
maintained by the Secretary in connection with these proceedings:23 
Jordan Kwok 
Thomas S. DeVita 
Director, Federal Regulatory Affairs 
Kimberly B. Frank 
Exelon Corporation 
Stuart B. Robbins 
701 Ninth Street, N.W. 
K&L Gates LLP 
Washington, D.C. 20068 
1601 K Street, NW 
(667) 313-0421 
Washington, DC  20006 
jordan.kwok@exeloncorp.com 
(202) 778-9000 
 
thomas.devita@klgates.com 
Alejandro Bautista 
kimberly.frank@klgates.com 
Assistant General Counsel 
stuart.robbins@klgates.com 
Exelon Corporation 
 
2301 Market Street 
Counsel for Exelon Corporation  
Philadelphia, PA 19101 
 
(267) 533-0120 
 
alejandro.bautista@exeloncorp.com 
 
 
 
22 See PJM Interconnection, About PJM (last visited Sept. 27, 2026), https://www.pjm.com/about-pjm.  
23 Exelon respectfully requests a waiver of Rule 203(b)(3), 18 C.F.R. § 385.203(b)(3), to allow the inclusion of 
more than two persons on the official service list.

12 
III. 
BACKGROUND 
The concept of a multi-year forward period for RPM first emerged in PJM’s August 
2005 Initial RPM Proposal,24 and was designed to address one of several core deficiencies with 
PJM’s then-existing capacity construct—namely that, as PJM explained, the construct did “not 
look far enough into the future to secure capacity in time to meet reliability needs.”25  In 2005, 
this defect was glaring.  At the time, PJM’s capacity construct only required that Capacity 
Resources be committed for one day, and there was little incentive to commit for longer 
periods.  Moreover, Capacity Resources were permitted to “opt out” of their Capacity Resource 
status with as little as 36 hours’ notice.  PJM administered capacity credit markets only twelve 
months at a time, which were designed to accommodate short-term competitive load-switching 
under retail choice, and were incapable of sustaining long-term generation investment.  As 
PJM described it, “[s]imply put, the short-term nature of the current PJM capacity construct is 
fundamentally inconsistent with the need to preserve system reliability in the longer term.”26  
To remedy these shortcomings, PJM proposed a four-year forward period for RPM.   
On April 20, 2006, the Commission issued its Initial RPM Order, finding that PJM’s 
existing capacity construct was unjust and unreasonable and establishing additional procedures 
to resolve several remaining issues regarding the just and reasonable replacement rate.27  As 
relevant here, the Commission accepted the four-year forward period of RPM, finding that 
 
24 PJM Interconnection, L.L.C., PJM Section 205 and 206 Filing of PJM Interconnection, L.L.C., Docket Nos. 
ER05-1410-000 and EL05-148-000 (Aug. 31, 2005) (“August 2005 Initial RPM Proposal”).  
25 Id., at 5. 
26 Id., at 9. 
27 PJM Interconnection, L.L.C., 115 FERC ¶ 61,079, at P 1 (2006) (“April 2006 Initial RPM Order”).

13 
“four years is a reasonable period in which solutions can be placed in operation in response to 
the RPM’s base residual auction.”28 
On September 29, 2006, PJM submitted the RPM Settlement, which proposed to 
resolve all outstanding issues in the proceeding regarding RPM.29  Among other things, the 
RPM Settlement retained a multi-year forward period accepted by the Commission in the April 
2006 Initial RPM Order, but shortened the period between the BRA and the start of the 
Delivery Year from four to three years.  As explained in the RPM Settlement, the parties 
determined three years was sufficient to meet the essential purpose of a forward commitment, 
namely to provide a credible prospect for new entry via the construction of new resources.30  
To this point, the settlement noted that PJM previously presented witness testimony indicating 
a typical 33-month period between signing of an Incremental Facilities Study Agreement for a 
new plant and the plant’s commercial operation date.31 
On December 22, 2006,32 the Commission approved the RPM Settlement, subject to 
certain conditions, including the proposed three-year-forward period of RPM.  Over the last 
twenty years, many of the RPM market design components from the original RPM Settlement 
have evolved and been improved upon, including capacity accreditation, performance 
obligations, and interface with PJM’s planning and operations regime.  Notably, however, with 
 
28 Id., at P 72. 
29 PJM Interconnection, L.L.C., Settlement Agreement and Explanatory Statement of the Settling Parties 
Resolving All Issues, Docket Nos. ER05-1410-000 and -001, EL05-148-000 and -001 (Sept. 29, 2006) (“RPM 
Settlement”).  
30 See RPM Settlement, at 11-12.  
31 Id.  
32 See PJM Interconnection, L.L.C., 117 FERC ¶ 61,331, at P 28 (2006) (“December Order Approving 
Settlement”).

14 
the exception of the BRA delays starting in 2019, the three-year forward period auction 
schedule has remained unchanged since 2006. 
IV. 
LEGAL ARGUMENT 
A. 
The Current Three-Year Forward Period of RPM is No Longer Just and 
Reasonable.  
i. 
The risk balancing analysis the Commission relied on in 2006 to accept 
the load forecast inaccuracies inherent in RPM’s multi-year forward 
period has fundamentally collapsed in 2026.   
As described above, the concept of a multi-year forward period was integral to PJM’s 
original RPM filing in 2005.  In the August 2005 Initial RPM Proposal, PJM predicated RPM 
on a four-year forward period (later revised down to three years via the RPM Settlement), 
which aligned with what was at the time the expected development schedule for a new 
combustion turbine (an estimated 33 months, as discussed above), according to PJM’s affiant 
Mr. Pasteris.33  From the outset, PJM acknowledged that RPM’s proposed multi-year forward 
period, by definition, contained an inherent risk of load forecast inaccuracies.  PJM explained 
that “the choice of the forward period represents a balance among many factors, including the 
risk of estimation error . . . and the ease of participation by resources with relatively long lead 
times.”34  In applying this “balancing” of factors, PJM reasoned that “what is crucial is a market 
that is sufficiently forward to provide the opportunity for additional competition and a greater 
degree of forward price certainty, while not being so long that the estimation errors create a 
substantial risk of too much construction should the expected load fail[] to materialize.”35  
 
33 See August 2005 Initial RPM Proposal, at 75-76. 
34 Id., at 77-78. 
35 Id., at 78.

15 
In its April 2006 Initial RPM Order approving RPM’s multi-year forward period, the 
Commission recognized what several protesters argued in the record—namely that “RPM may 
expose customers to greater risks than they now face,” including “the inherent risk that a four-
year-forward estimate of how much capacity will be needed five years later will prove to be 
unreliable.”36  The Commission acknowledged these concerns were valid, but engaged in a 
risk balancing analysis to justify acceptance of the risk of inaccuracy inherent in RPM’s multi-
year forward period.   
We agree, in part, with Morgan Stanley that RPM may cause 
customers to bear risks such as the risk that a four-year forward 
estimate of needed capacity may turn out to be inaccurate.  
However, we think that the risk is reasonable when it is 
compared to the risks of the current construct, namely that 
sufficient capacity resources may not be constructed to ensure 
the preservation of reliability.37 
Twenty years later, this risk-balancing analysis the Commission relied on in 2006 has 
fundamentally collapsed, and the resulting RPM framework that was explicitly predicated on 
it has become unjust and unreasonable.  As demonstrated below, not only have the load forecast 
inaccuracies inherent in RPM’s three-year forward period increased since 2006, but Capacity 
Resources—and in particular the RPM Reference Resource38—are now functionally incapable 
of being constructed in the PJM Region within the current three-year cycle, leaving only the 
downside pricing risk of those load forecast inaccuracies to be borne by customers.  Put another 
way, the very outcome the Commission sought to avoid in accepting the load forecast 
 
36 April 2006 Initial RPM Order, at P 66.  It is worth noting that the three-year forward period of RPM is 
functionally a “three year + one year” estimate and commitment by customers. 
37 Id., at P 71 (emphasis added). 
38 See Tariff, Definitions R-S (“Reference Resource” shall mean a combustion turbine generating station, 
configured with a single General Electric Frame 7HA turbine with evaporative cooling, Selective Catalytic 
Reduction technology all CONE Areas, dual fuel capability, and a heat rate of 9.134 Mmbtu/ MWh.”).

16 
inaccuracies inherent in RPM’s multi-year forward period—“that sufficient capacity resources 
may not be constructed to ensure the preservation of reliability”—is today the lived reality of 
the PJM Region.  This conclusion is supported by several key pieces of evidence, which are 
described below in subsections IV.A.i.a and IV.A.i.b.   
a. 
Evidence that PJM Load Forecast Inaccuracies Have Increased 
Since 2006. 
As noted above, Exelon has taken concrete steps to improve the accuracy of its load 
forecast and eliminate speculative demand, including through its pioneering use of TSAs, 
which require firm financial commitments from large load customers.39  Notwithstanding these 
efforts, Exelon, the other Transmission Owners of the PJM Region, and PJM itself are 
nonetheless bound by RPM’s requirement to predict reality years into the future—a task made 
more difficult by the nature, characteristics, and volatile development schedules of today’s 
large loads.  Beyond this, a forward period of this magnitude will, by definition, fail to capture 
changes in business economics, federal and state environmental and regulatory policy, and 
local siting and permitting regulations, all of which play a vital role in the market outcomes of 
RPM. 
Irrespective of the efforts of Exelon, the PJM Transmission Owners, and PJM to 
enhance the accuracy of their load forecasts, RPM’s mandate to predict reality so far into the 
future creates uncertainty in PJM’s near-term load forecast that is persistent, consistent in 
direction, and has increased in magnitude since 2006 when the Commission initially accepted 
RPM’s three-year forward period.  There are multiple data sets that support this conclusion.  
First, Figure 2 of the Nicholson Affidavit illustrates the change in the peak load forecast 
 
39 More information about TSAs is available here: https://www.exeloncorp.com/grid/exelons-transmission-
security-agreements-a-pioneering-model-for-customer-protection1.

17 
between the BRA, which has historically been held thirty-eight (38) months prior to the start 
of the Delivery Year, and the third IA, which is held approximately four months before the 
start of the Delivery Year.  The magnitude of the load forecast inaccuracies (blue bars) between 
the 2016/2017 BRA and the 2022/2023 BRA is significant, reveals a clear trend toward 
overestimation of load, and notably the need for forecast adjustments decreased in instances 
where the BRA forward period was shortened as a result of auction delays.  As Dr. Nicholson 
explains, the increase in BRA load forecast precision shown in  Figure 2 of the Nicholson 
Affidavit is positively correlated with the shorter forecast horizon, as the 2023/24 through 
2026/27 BRAs had a shorter forward period due to auction delays.40  
Nicholson Affidavit - Figure 2  
BRA Forward Period (Green, Right Axis) and Load Forecast 
Change between BRA and Third IA (Blue, Left Axis) 
 
 
Second, the increase in magnitude in recent years of PJM load forecast inaccuracies 
can also be observed in the growing size (in MW) of the Load Adjustments PJM makes to its 
 
40 Nicholson Affidavit, at ¶¶ 15-16. 
38
38
38
35
38
38
38
13 12
18
11
0
5
10
15
20
25
30
35
40
-9%
-7%
-5%
-3%
-1%
1%
3%
2016/17
2017/18
2018/19
2019/20
2020/21
2021/22
2022/23
2023/24
2024/25
2025/26
2026/27
BRA  forward period, in months
%  change, BRA   v. 3rd  IA

18 
load forecast model, which Dr. Nicholson describes in Table 2 of her Affidavit.  Where such 
adjustments historically represented no more than 2% of the projected summer peak load four 
to five years out as recently as the 2017 through 2021 forecasts, PJM’s 2026 forecast reflects 
adjustments of 18.4% and 21.7% of the summer peak for those same time horizons.41  Indeed, 
projected year-over-year growth in summer peak tells the same story, rising from well under 
1% annually as recently as 2022 to a range of 3.1% to 4.4% in PJM’s 2025 load forecast and 
2.6% to 6.7% in the 2026 forecast.42  This trend in year-over-year growth is illustrated in Table 
3 of the Nicholson Affidavit. 
Nicholson Affidavit - Table 2  
Load Adjustments as a Percent of the Summer Peak Load Forecasts, 2017 - 2026  
Historical PJM Load Forecasts by Year 
  
2017 
2018 
2019 
2020 
2021 
2022 
2023 
2024 
2025 
2026 
Y0 
0.6% 
0.8% 
1.1% 
0.0% 
-0.2% 
0.6% 
1.9% 
1.8% 
2.3% 
4.1% 
Y0 +1 
0.7% 
1.0% 
1.3% 
0.1% 
-0.1% 
1.1% 
2.2% 
3.0% 
5.3% 
6.7% 
Y0 +2 
0.8% 
1.2% 
1.5% 
0.3% 
-0.1% 
1.6% 
2.4% 
4.8% 
8.3% 
9.8% 
Y0 +3 
1.0% 
1.4% 
1.6% 
0.4% 
0.0% 
2.0% 
2.5% 
6.3% 
11.4% 
13.0% 
Y0 +4 
1.2% 
1.6% 
1.8% 
0.5% 
0.1% 
2.6% 
2.6% 
7.8% 
14.4% 
18.4% 
Y0 +5 
1.4% 
1.7% 
1.9% 
0.4% 
0.0% 
2.7% 
2.7% 
8.9% 
17.8% 
21.7% 
 
Nicholson Affidavit - Table 3  
Year-Over-Year Growth in Summer Peak Load Forecasts, 2017 - 2026  
Historical PJM Load Forecasts by Year 
  
2017 
2018 
2019 
2020 
2021 
2022 
2023 
2024 
2025 
2026 
Y0+1 
0.6% 
0.2% 
-0.3% 
1.0% 
0.5% 
0.3% 
0.5% 
1.5% 
3.1% 
2.6% 
Y0+2 
0.2% 
-0.3% 
0.4% 
1.0% 
0.6% 
0.6% 
0.8% 
2.2% 
3.3% 
3.2% 
Y0+3 
-0.4% 
0.3% 
0.5% 
0.6% 
0.4% 
0.6% 
1.2% 
1.9% 
3.5% 
3.6% 
Y0+4 
-0.2% 
0.3% 
0.4% 
0.4% 
0.3% 
0.7% 
1.0% 
1.9% 
3.6% 
6.7% 
Y0+5 
0.0% 
0.5% 
0.4% 
0.6% 
0.2% 
0.0% 
0.9% 
1.7% 
4.4% 
4.4% 
 
As Dr. Nicholson notes, this is not a modeling failure; it reflects a structural shift in 
forecast uncertainty driven almost entirely by the nature and size of data center load growth in 
 
41 Id., at ¶¶ 20-21. 
42 Id., at ¶ 22.

19 
the PJM Region.  Not only is such uncertainty larger in magnitude given the size of the 
underlying customers, but the forecasting challenges are also amplified by recent and ongoing 
siting, permitting, and supply chain challenges nationwide, as well as the fast-changing 
business environment and evolving regulatory constructs with which data center developers 
need to contend with.43  These load forecast inaccuracies have real impacts on market 
outcomes.  As Dr. Nicholson explains, the three-year RPM forward period and assumptions 
about large load growth, principally from data centers, are likely to overstate the peak load 
forecast that PJM uses to determine the Reliability Requirement and the amount of capacity 
that PJM must procure in the BRA.44  This can lead to unjust and unreasonable outcomes.  
Procuring too much capacity in the BRA unnecessarily increases costs for PJM Market 
Participants, because if a portion of the large loads included in the load forecast used in the 
BRA do not materialize, capacity costs will increase for all customers.  This outcome is also 
economically inefficient, because when it occurs the PJM Region purchases more capacity 
than is necessary to ensure target levels of resource adequacy.   
Dr. Nicholson provides an illustrative example to demonstrate just how much load 
forecast inaccuracies can impact market prices, even in small percentages.  Figure 3 of the 
Nicholson Affidavit is based on a VRR Curve constructed using PJM’s 2029/30 BRA 
parameters, the VRR Curve formulation the Commission accepted in Docket No. ER26-455, 
and no price collar.  As Dr. Nicholson explains, the blue plot shows an estimate of what the 
VRR Curve would be with the Reliability Requirement for the 2029/30 BRA, and the orange 
 
43 Id., at ¶¶ 14, 21-23, 27. 
44 Id., at ¶ 14.  Note that the PJM Region Reliability Requirement is defined as the Forecast Pool Requirement 
multiplied by the Preliminary PJM Region Peak Load Forecast, less the sum of all Preliminary Unforced Capacity 
Obligations of 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.”

20 
and green plots show what the VRR Curve would have been if the Reliability Requirement 
were 1% or 2% lower, respectively.45  Both 1% and 2% are reasonable load forecast 
sensitivities to explore because they are consistent with historically observed forecast errors 
within a three-year forecast horizon in the 2016/17 through 2022/23 BRAs (see Figure 3 of the 
Nicholson Affidavit), which occurred before the uncertainty inherent in large load growth seen 
today.  Additionally, when comparing the PJM load forecasts published in January 2025 and 
January 2026, the Summer Peak forecasts for 2027 through 2029 fell by between 2.3% and 
2.6%.46  
Nicholson Affidavit - Figure 3 
Illustrative Example of Cost Implications of the Reliability Requirement on the BRA 
Clearing Price 
 
 
 
45 Id., at ¶ 29. 
46 Id. 
$0
$50
$100
$150
$200
$250
$300
$350
$400
$450
$500
$550
$600
$650
140,000
142,500
145,000
147,500
150,000
152,500
155,000
157,500
160,000
$ / UCAP MW-day 
UCAP MW
29/30 RR
1% lower RR
2% lower RR
Price cap = $594.48
1/2 of price cap
101.5% of RR
106% of RR
Lower RR shifts VRR curve to the left

21 
If one were to assume that, as may happen in a tight market, the BRA were to clear on 
the sloped portion of the VRR Curve, Figure 3 of the Nicholson Affidavit shows that a 1% 
shift in the Reliability Requirement could reduce the capacity price by approximately 
$120/UCAP-MW-day, and a 2% reduction could lead to a price reduction of approximately 
$120-220/UCAP MW-day, depending on the capacity the auction clears.  This translates to 
approximately $6 to $12 billion in change in total capacity costs to customers resulting from a 
historically “normal” level of load forecast error associated with a three-year forward period.47   
b. 
Evidence that Capacity Resources cannot be constructed in the 
PJM Region within the current three-year cycle. 
There are multiple pieces of evidence supporting the conclusion that, in 2026, Capacity 
Resources cannot be constructed in the PJM Region within the current three-year forward 
period, thereby undermining the key ‘counterweight’ the Commission used in its balancing 
analysis in 2006 to justify being willing to accept the load forecast inaccuracies inherent in a 
multi-year forward period of RPM. 
First, as a threshold matter, it is worth noting that PJM itself has reached this 
conclusion.  In the PJM White Paper, PJM explained that while “[t]he three-year forward 
timeline was originally established because it aligned with the construction schedule of many 
of the resources that could be built to meet the system’s resource adequacy needs, including 
both combustion turbine and combined cycle gas turbine resources,” this “foundational 
assumption of the RPM design has been physically broken.”48  PJM concluded that “[t]oday, 
due to compounding frictions in siting, permitting, supply chains and interconnection, it can 
 
47 Id. at Table 5, ¶¶30-31. 
48 PJM White Paper, at 18.

22 
take two or three times as long to build a gas resource as it does to build a hyperscale data 
center.”49  
Second, despite notable reforms to PJM’s interconnection queue that are designed to 
make the standard Cycle study one to two years in duration, data indicates that Capacity 
Resources are still experiencing significant difficulty entering service at all, let alone within 
the three-year forward period of RPM.  For example, since 2020, approximately 24 GW of 
planned generation with fully executed interconnection agreements have terminated their 
agreements before reaching commercial operation, including 13.5 GW of natural gas 
capacity.50  These terminations have largely been caused by matters external to PJM, and 
continue to inhibit the deployment of new capacity to the PJM Region.  Indeed, in May 2026 
PJM reported that “~53 GW of interconnection projects – enough to power 40 million homes 
at full output – currently have signed agreements to connect to the grid, but many are being 
stymied by issues beyond PJM’s control, like federal, state and local permitting, siting, and 
supply chain challenges.”51  Additionally, as Dr. Nicholson explains, a recent analysis of 
PJM’s interconnection queue between 2015 and 2024 found that new large natural gas-fired 
generation projects that completed the interconnection process had an average timeline of 10.8 
years between initial submission into the queue and commercial operation.52  This study also 
 
49 Id.  
50 Nicholson Affidavit, at ¶ 34. 
51 See PJM, New, Faster Generation Interconnection Process Fact Sheet (Updated May 21, 2026), 
https://www.pjm.com/-/media/DotCom/about-pjm/newsroom/fact-sheets/interconnection-reform-progress-fact-
sheet.pdf.  
52 Nicholson Affidavit, at ¶ 34 (citing Ralph O’Connor Sustainable Energy Inst., Johns Hopkins Univ., Natural 
Gas Generator and Energy Storage Timelines in PJM, at 2-3 (May 18, 2026)).

23 
found that, since 2015, of 102 gas-fired generators over 100 MW that entered into the PJM 
queue, only thirteen were online by early 2026 (eleven years later).53   
Third, recent evidence indicates that the global shortage of gas turbines—the 
technology underlying RPM’s reference resource (and combined cycle gas turbine resources 
as well)—has made three-year entry functionally impossible.  As Dr. Nicholson explains, 
major manufacturers have reported backlogs stretching years into the future.  For example, 
Siemens Energy disclosed an approximately 69 GW order backlog as of August 2026, with 
new orders now quoting lead times of three years or more.  GE Vernova similarly reported a 
116 GW backlog it expected to exceed 125 GW by year-end 2026, and Mitsubishi’s gas turbine 
lead times have grown from roughly two years just after the pandemic to five years or more 
today, with the company now booking deliveries as far out as 2031 to 2034.54   
Fourth, recent markets data and rule changes indicate the current market environment 
is no longer conducive to new resource entry within the three-year forward period of RPM.  
This is perhaps most clearly illustrated by the recent BRA results, which conclusively 
demonstrate the current construct is failing to procure adequate capacity, even as prices have 
reached their regulatory ceiling.55  In particular, the 2027/2028 and 2028/2029 BRAs each 
cleared at the Commission-approved price cap (most recently $325.00/MW-day in the Rest of 
RTO zone for the 2028/2029 BRA) while simultaneously failing to procure the full Reliability 
Requirement, falling short by 6,517 MW UCAP and 6,831 MW UCAP, respectively.56  
Notably, the 2029/2030 BRA, scheduled for December 2026, will again be subject to a price 
 
53 Id. 
54 Id., at ¶ 35. 
55 Id., at ¶ 7. 
56 Id.

24 
cap, set at $337.83/UCAP MW-day.57  It is also worth noting that future auctions, beyond the 
2029/2030 Delivery Year, are slated to be run on an uncapped basis, a factor that will allow 
prices to further rise to the regulatory maximum price and that generation developers would 
naturally incorporate into their commercial outlooks for new generation revenue.   
At the same time, PJM recently pursued alternative procurement mechanisms that offer 
long-term investment certainty superior to the three-year forward period of RPM.58  
Specifically, the RBP, which the Commission accepted and suspended for further briefing on 
September 30, 2026, would procure capacity from new resources on a pay-as-bid basis for 
terms of up to fifteen years, subject to a weighted-average price cap of $555/MW-day, for 
resources expected to be in service by June 1, 2032.59   Because a Capacity Resource that clears 
an RPM Auction is ineligible for an RBP auction, these long-term procurement mechanisms 
compete directly with (and, given their superior revenue certainty, are likely to draw 
developers away from) the three-year forward BRA, which offers only a single-year 
commitment.60  The scale of that pull is already evident, with PJM reporting that roughly 136 
GW of potential new capacity, spanning 397 projects and 87 entities, have expressed interest 
in RBP auctions or in facilitated bilateral matching in response to its request for interest.61  As 
Dr. Nicholson explains, it is highly unlikely that a  rational investor would forgo a long-term 
commitment of up to fifteen years under an RBP auction or potentially similar certainty under 
a contract directly with a large load, in favor of a single Delivery Year’s worth of revenue 
 
57 Id., at ¶ 9. 
58 Id., at ¶ 67. 
59 Id.  
60 See id. 
61 Id.

25 
certainty under the BRA, particularly now that lenders financing new merchant generation 
generally insist on exactly the kind of long-term offtake commitment that only those alternative 
multi-year mechanisms can offer.62   
In summary, there is ample evidence that the risk balancing analysis the Commission 
relied on in 2006 has collapsed in 2026.  Not only have the load forecast inaccuracies inherent 
in RPM’s three-year forward period increased considerably since 2006, but Capacity 
Resources are now functionally incapable of being constructed in the PJM Region within the 
current three-year cycle, leaving only the downside pricing risk of those load forecast 
inaccuracies to be borne by customers.   
ii. 
The prospective assumptions in 2006 regarding the ability of RPM’s 
multi-year forward period to incentivize LSE bilateral contracting and 
risk hedging have been disproven over the course of 20 years. 
One of the key ideas put forward in the August 2005 Initial RPM Filing was that RPM’s 
multi-year forward period would help facilitate LSE bilateral contracting and risk hedging.  
PJM explained that “[l]onger term price signals [] should incent longer term bilateral contracts, 
as an effective means of hedging the reliability charges assessed under RPM.”63  In support of 
this proposition, PJM included testimony from Andrew Ott, then PJM’s Vice President of 
Market Services.  Mr. Ott explained that this anticipated enhanced incentive for LSE bilateral 
contracting and risk hedging would “help orient market participant objectives with the 
system’s reliability needs, and help ensure the long-term viability of the competitive market 
model in the electric industry.”64   
 
62 See id. 
63 August 2005 Initial RPM Proposal, at 77. 
64 Id. at Ott Affidavit ¶ 15.

26 
Several protesters raised concerns with PJM’s prognostications regarding RPM’s 
positive impact on LSE bilateral contracting and risk hedging, arguing that, contrary to PJM’s 
predictions, “RPM will impair parties’ willingness and ability to manage risk: since all parties 
will be fully hedged prior to each Delivery Year, there will be no incentive for parties to 
manage their own risk by entering into additional bilateral contracts.”65  Protesters further 
argued that “if the market becomes less volatile, parties will be less motivated to enter into 
bilateral agreements even before entering the capacity markets.”66 
In response, PJM acknowledged that “RPM will affect bilateral contracting in the PJM 
region, just as LMP affected bilateral contracting,” but argued that “the impact will be 
beneficial from the standpoint of system reliability, as it will encourage contracts of four years 
or more.”67 PJM argued that, under the current structure, “LSEs that have an orientation 
towards short time horizons are not entering into long-term contracts” and that “[t]o the extent 
RPM begins to induce a change in contracting towards agreements that come closer to 
reflecting those costs and supporting those investments [necessary to maintain a reliable 
system], then it is a change worth making, and one the Commission should support as a matter 
of policy.”68 
In its April 2006 Initial Order approving RPM’s multi-year commitment period, the 
Commission accepted PJM’s assumptions and predictions regarding the incentivization of LSE 
bilateral contracting and risk hedging, stating:   
 
 
65  April 2006 Initial Order, at P 65. 
66 Id. 
67 PJM Interconnection, L.L.C., Motion for Leave to Answer and Answer of PJM Interconnection, L.L.C, at 35 
(Sept. 16, 2005). 
68 Id., at 35-36.

27 
The Commission does not consider it likely that RPM will 
lessen parties’ motivation to purchase more of their forward-
looking capacity needs through bilateral contracts, or to 
manage their risk in other ways, such as releasing or 
purchasing additional capacity in the auctions following the 
Residual Base Auction during the four years prior to each 
Delivery Year.  First, those states or LSEs who wish to maintain 
maximum flexibility to manage their own risk will be able to 
fulfill their own capacity needs by providing their own fixed 
resource requirement.  Second, as PJM has alleged, parties are 
not engaging in significant amounts of forward contracting 
now: RPM will provide more information to all market 
participants, and all parties will be able to use this information 
to manage their risk more effectively, whether through 
bilateral contracting or otherwise.  Moreover, the series of 
follow-on auctions for each Delivery Year will enable LSEs to 
adjust the amounts of capacity they hold, or to seek to obtain 
capacity at a better price, until four months before the Delivery 
Year.69 
These prospective predictions and assumptions made in 2006 regarding the impact of 
RPM’s multi-year forward period on LSE bilateral contracting and risk hedging have been 
comprehensively disproven over the course of 20 years.  The anticipations of PJM and the 
Commission, that RPM would lead to a broad propagation of bilateral contracting and hedging, 
and the associated reasoning used in support of accepting the three-year forward period, have 
not come to pass.  This conclusion is supported by several pieces of evidence.   
First, PJM itself identified that a significant portion of PJM load is presently served by 
entities that rely on short-term procurement rather than long-term bilateral contracts to meet 
their capacity needs, leaving those entities (and the retail customers they serve) directly 
exposed to RPM price volatility, rather than hedged against it. And, as a corollary, 
opportunities for long-term contracting between those entities and Capacity Resources have 
been equally limited.  In the PJM White Paper, PJM explained that: 
 
69 April 2006 Initial Order, at P 70 (emphasis added).

28 
A significant portion of PJM load is served by default service 
providers – state-regulated entities that are often constrained by 
statute or regulatory practice from entering long-term bilateral 
contracts. These entities procure capacity primarily through 
short-term default service auctions calibrated to the annual 
Base Residual Auction cycle. During PJM’s prolonged surplus 
era, this approach was rational: short-term procurement 
captured low market prices without paying a long-term hedge 
premium. But it also left these entities – and their retail 
customers – exposed to capacity price volatility when the market 
transitioned into scarcity. This effect was exacerbated by the 
persistent capacity auction delays experienced in PJM.70 
Similarly, in PJM’s February 2025 filing to establish a revised price cap and price floor 
for the 2026/2027 and 2027/2028 Delivery Years, PJM’s Executive Vice President for Market 
Services and Strategy Stu Bresler explained that although the RPM was initially expected to 
be a residual market, with the majority of capacity contracted bilaterally, that contracting has 
not occurred.  Instead, Mr. Bresler explained that “[r]ather, it appears that substantial load in 
the states that have expressed concern are directly exposed to Base Residual Auction prices for 
the entirety of their capacity obligations.”71  It was precisely because of this absence of long-
term contracting that PJM presented “Path A” in the PJM White Paper, which envisions 
enhanced requirements for LSEs to sign long-term capacity contracts to support investment in 
new capacity resources and to act as a hedge against volatility in capacity market prices.72  
 
70 PJM Whitepaper, at 29-36.  
71 PJM Interconnection, L.L.C., Affidavit of Mr. Frederick S. Bresler III on Behalf of PJM Interconnection, 
L.L.C., at 6, Docket No. ER25-1357-000 (Feb. 20, 2025), emphasis added (“The original vision of the RPM was 
for it to function primarily as a residual market, with the majority of capacity procured through bilateral contracts 
and only a small portion needed to cover remaining needs from the market. Participation in this way as originally 
intended would serve to substantially hedge market participants on both the supply and demand sides from 
uncertain and potentially volatile Base Residual Auction clearing prices. The historic and existing capacity market 
design and results do not appear to have sufficiently stimulated this type of activity. Rather, it appears that 
substantial load in the states that have expressed concern are directly exposed to Base Residual Auction prices 
for the entirety of their capacity obligations.”). 
72 PJM Whitepaper, at 32-34.

29 
Second, in many PJM jurisdictions, LSEs are restricted by state law from engaging in 
the kinds of long-term bilateral contracting and hedging that the Commission envisioned in 
2006 when approving the three-year forward period of RPM.  Exelon Affiant Deborah Sears 
submits direct testimony on this point into the record, describing in detail the range of 
restrictions on long-term bilateral contracting and hedging in the District of Columbia, 
Maryland, New Jersey, and Delaware.  As Ms. Sears notes, “[t]he SOS/BGS auction structures 
are highly prescriptive and any changes to the annual auction process are reviewed through a 
stakeholder meeting called the Procurement Improvement Process, and the final changes to the 
Request for Proposal and Full Requirements Service Agreement require approval by the 
applicable state utility regulatory commission.”73  As Ms. Sears puts plainly, “Pepco, DPL, 
and ACE are not permitted to enter into any bilateral transactions including hedging 
agreements without approval from the applicable state utility regulatory commission.”74   
Third, beyond restrictions in state law, restrictions in federal law have also been 
identified by certain states as an obstacle to long-term bilateral contracting and hedging.  To 
this point, and as further referenced by Dr. Nicholson, a New Jersey Board of Public Utilities 
(“NJBPU”) examination of the PJM capacity market explained that federal legal restrictions 
limit the types of bilateral contracting the state of New Jersey can engage in to procure capacity 
bilaterally on a long-term basis outside of the RPM.75  The NJBPU assessment found that 
“[t]he only way an LSE can use capacity procured wholly outside the RPM to meet its capacity 
needs is by electing to use the Fixed Resource Requirement (“FRR”) Alternative under which 
 
73 Sears Affidavit, at ¶ 9.  
74 Id.   
75 Nicholson Affidavit, at ¶ 38 (citing New Jersey Board of Public Utilities, An Investigation of PJM’s Capacity 
Market, at 6 (Aug. 2026)).

30 
it must meet all of its capacity needs outside of the RPM for the relevant service area.  
However, the Reliability Assurance Agreement effectively bars LSEs in states like New Jersey 
that allow full retail choice from electing the FRR Alternative.”76  The Assessment went on to 
explain that the state of New Jersey attempted to make long-term bilateral capacity 
procurements through the Long-Term Capacity Pilot Program, but courts found the program 
was preempted by the Federal Power Act in PPL v. Hannah77 and PPL v. Solomon.78  The 
NJBPU further explained that Hughes v. Talen79 put further limits on the types of long-term 
bilateral capacity contracting PJM states can engage in.  As a result of these federal legal 
constraints, NJBPU concluded that “to date New Jersey LSEs have opted to procure the 
capacity they needed exclusively or nearly exclusively through RPM auctions.”80   
In summary, the prospective assumptions and predictions of PJM and the Commission 
in 2006 regarding the ability of RPM’s multi-year forward period to incentivize LSE bilateral 
contracting and risk hedging have not come to pass over the last 20 years. 
iii. 
The current three-year forward period inhibits efficient resource exit 
and Deactivation, as it requires generation owners to invest in the 
absence of reasonable predictability in future operational capability 
and environmental policy.   
Under PJM’s Capacity Performance construct, cleared Capacity Resources with RPM 
commitments are required to be available to operate throughout the Delivery Year, pursuant to 
RPM’s must-offer requirements.  Capacity Resources have particular performance obligations 
when scheduled and/or dispatched by PJM during a Performance Assessment Interval 
 
76 Id. 
77 PPL Energyplus, LLC v. Hanna, 977 F.Supp. 2d 372, 389-390 (D.N.J. 2013).  
78 PPL EnergyPlus, LLC v. Solomon, 766 F.3d 241, 246 (3rd Cir. 2014). 
79 Hughes v. Talen Energy Mktg., LLC, 578 U.S. 150 (2016).  
80 Nicholson Affidavit, at ¶ 38.

31 
(“PAI”).81  Capacity Resources that fail to perform when called upon face severe financial 
penalties, or as PJM has described it, “[g]enerators assume virtually all financial risks if they 
do not meet their power supply obligations.”82 
In deciding how to bid their Capacity Resources into RPM and at what price, all 
resource owners must engage in a business risk balancing analysis that weighs the potential 
revenues that might be earned in a given RPM Auction against the cost of continuing to operate 
a given Capacity Resource, including the Capacity Performance risk associated with failing to 
perform when called upon during a PAI.  Indeed, PJM’s rules explicitly acknowledge these 
considerations in the construction of a resource’s Avoidable Cost Rate (“ACR”), which 
represents the ongoing fixed operation and maintenance costs a Capacity Resource can avoid 
if it does not operate for a given Delivery Year, and in a resource’s Capacity Performance 
Quantifiable Risk (“CPQR”), which measures and values the expected financial risks and 
potential performance penalties that a Capacity Resource may face during emergency 
operations. 
For the owners of older Capacity Resources that may be trying to ascertain whether it 
is economic to remain in the market or exit through Deactivation, the three-year forward period 
of RPM profoundly clouds this balancing analysis.  The reason for this is simple—these 
resource owners cannot see three years (and in practice, four years) into the future.  As a result, 
they are unable to make two important determinations: (i) whether they will be able to 
physically operate their resource dependably during the future Delivery Year; and (ii) whether 
 
81 See Tariff, Attachment DD, Section 5.5A(a). 
82 See PJM Interconnection, Capacity Performance at a Glance (last visited Sept. 27, 2026), 
https://www.pjm.com/-/media/DotCom/library/reports-notices/capacity-performance/20150720-capacity-
performance-at-a-glance.ashx?la=en.

32 
applicable environmental policy will legally allow them to operate their resource during the 
future Delivery Year.  Furthermore, given the various uncertainties in play, Capacity Resource 
owners may also struggle to predict future system conditions and therefore estimate the volume 
of Capacity Performance exposure.  Accordingly, even if it would be efficient for the market, 
economic for the resource owner, and beneficial to reliability as a whole for the Capacity 
Resource to remain in the market, these resource owners are incapable of conducting an 
accurate risk assessment and are thus inadvertently incentivized to exit the market earlier than 
may be appropriate.  These operational and environmental policy uncertainties are described 
below, in the following subsections IV.A.iii.a and IV.A.iii.b. 
a. 
Operational Uncertainties 
A key consideration for the owner of a Capacity Resource contemplating Deactivation 
is whether they will be physically able to dependably operate their resource during the future 
Delivery Year.  By definition, many of the resources contemplating Deactivation are old and 
nearing the end of their operational life.  This reality tends to exacerbate several factors critical 
to the predictability of future operations.  The first is the availability and long-term 
procurement of fuel.  Global instability, supply chain disruptions, transportation and storage 
bottlenecks, and contractual rigidity in price/volume take, duration, and collateral credit 
requirements can make accurately forecasting the price and future availability of both the fuel 
commodity itself and delivery challenging, particularly for resources that may be operating 
under shorter time horizons due to their vintage. 
The second factor that can exacerbate uncertainty around the future ability of an older 
Capacity Resource to operate is project investment.  These facilities tend to need significant 
investment in their physical plant to continue reliable operations when compared to newer 
facilities.  In PJM, this fact can be seen in the scale of identified project investment for units

33 
that are required to continue operations via Reliability Must-Run (“RMR”) arrangements with 
the RTO.  For example, in its April 18, 2024, application for cost recovery for the Brandon 
Shores facility in Maryland, Talen Energy identified nearly $30,000,000 in anticipated project 
investment to ensure the availability of the facility for PJM scheduling and dispatch.83   
Finally, employee retention has remained an ongoing challenge for resource owners, 
as an aging workforce and the geographic isolation of many power plants limits the availability 
of skilled personnel needed to operate these facilities, particularly as they near the end of their 
useful life.  Additionally, competition for the labor skill sets required to operate power plants 
is also increasing from other sectors of the economy.  To this point, the Department of Energy 
in its 2026 United States Energy and Employment Report, (“USEER”) found that “energy 
employers are increasingly competing for workers not only with other energy companies, but 
also with fast-growing data centers, infrastructure projects, advanced manufacturing facilities, 
and critical minerals industries” as “[t]hese sectors rely on many of the same skilled 
occupations, including electricians, electrical engineers and technicians, industrial 
maintenance workers, construction trades workers, and production workers.”84  These 
challenges can add to uncertainty regarding the staffing needed to ensure the operational 
availability of Capacity Resources in the future. 
b. 
Environmental Policy Uncertainties 
In addition to the operational uncertainties described above, a key consideration for the 
owner of a Capacity Resource contemplating Deactivation is whether they will be able to 
 
83 Brandon Shores LLC, Continuing Operations Rate Schedule of Brandon Shores LLC, Docket No. ER24-1790-
000, at 18 (Apr. 18, 2024). 
84 U.S. Dep’t of Energy, 2026 United States Energy and Employment Report, at 24 (2026), 
https://www.energy.gov/documents/2026-useer-national-report.

34 
legally operate their resource, and under what environmental regulations, during the future 
Delivery Year.  Environmental regulations at both the federal and state level directly impact 
the operation of Capacity Resources, and can change significantly from year to year. 
For example, federal environmental policy has been particularly volatile in recent 
years, as reflected in Figure Exelon-1, which illustrates the major changes to federal carbon 
dioxide regulation policy that have occurred just over the last decade.

35 
Figure Exelon-1 
Major Changes in Federal Regulation of Carbon Dioxide 
2015-2026 
Date 
Federal Carbon Dioxide Regulation Event 
August 3, 2015 
The EPA finalizes the Clean Power Plan, which aims to reduce 
carbon dioxide emissions from the power sector by 32% below 2005 
levels by 2030.85 
February 9, 2016 
The United States Supreme Court stays the implementation of the 
Clean Power Plan, pending further proceedings before the United 
States Court of Appeals for the District of Columbia Circuit (“D.C. 
Circuit”).86 
June 19, 2019 
The EPA finalizes the Affordable Clean Energy Rule, which repeals 
the Clean Power Plan.87 
January 19, 2021 
The D.C. Circuit vacates the Affordable Clean Energy Rule.88 
June 30, 2022 
The United States Supreme Court rejects EPA’s attempt to revive 
the Clean Power Plan, and limits EPA’s ability to regulate carbon 
dioxide emissions from power plants under the Clean Air Act.89  
April 25, 2024 
The EPA announces final Carbon Pollution Standards requiring that 
all long-term coal-fired plants and base load new gas-fired plants 
control 90% of their carbon emissions.90 
September 17, 2026 
The EPA repeals most of the Carbon Pollution Standards and 
solicits comment on additional reasons to rescind all greenhouse gas 
emission requirements for fossil fuel-fired generators.91 
 
 
85 See U.S. Env’t Prot. Agency, Fact Sheet: Overview of the Clean Power Plan (last updated May 9, 2017), 
https://archive.epa.gov/epa/cleanpowerplan/fact-sheet-overview-clean-power-plan.html 
86 
See 
Chamber 
of 
Commerce 
v. 
EPA, 
136 
S. 
Ct. 
999 
(2016) 
(order 
granting 
stay), 
https://www.supremecourt.gov/orders/courtorders/020916zr3_hf5m.pdf. 
87 See U.S. Env’t Prot. Agency, Affordable Clean Energy (last updated Mar. 12, 2026),  
https://www.epa.gov/stationary-sources-air-pollution/affordable-clean-energy-rule. 
88 Am. Lung Assoc. v. EPA, 985 F.3d 914 (D.C. Cir. 2021). 
89 W. Va. vs. EPA, 597 U.S. 697 (2022). 
90 See U.S. Env’t Prot. Agency, Supporting Information – Final Greenhouse Gas Standards and Guidelines for 
Fossil Fuel-Fired Power Plants (last updated May 20, 2026), https://www.epa.gov/stationary-sources-air-
pollution/supporting-information-final-greenhouse-gas-standards-and. 
91 See Partial Repeal of the Carbon Pollution Standards for Fossil Fuel-Fired Electric Generating Units, 91 Fed 
Reg. 58,954 (Sept. 17, 2026), https://www.federalregister.gov/documents/2026/09/17/2026-19071/partial-repeal-
of-the-carbon-pollution-standards-for-fossil-fuel-fired-electric-generating-units.

36 
The impact of federal environmental policy can also be seen in the words of PJM 
resource owners themselves, through their Deactivation notices to PJM.  For example, in its 
July 22, 2025, Deactivation notice to PJM for the Kincaid facility, Vistra Corp. explained that 
“[t]he Kincaid Units will cease operations by this date in order to comply with the U.S. 
Environmental Protection Agency’s (EPA) Coal Combustion Residual (CCR) Rule, 40 C.F.R. 
Part 257, Subpart D.”92 
Beyond federal environmental policy, uncertainty and future assumptions regarding 
state environmental policy can also impact Deactivation decisions.  Indeed, a review of 
generator Deactivation notices in PJM from the last three years makes clear that prospective 
assumptions regarding the future applicability of state environmental regulations are a key 
driver for Deactivation decisions in the PJM Region, as illustrated in Figure Exelon-2.   
Figure Exelon-2 
References to State Environmental Regulations in PJM Deactivation Notices 
2023-2026 
Deactivation 
Letter 
Date 
Reason Given in Deactivation Letter 
Cumberland 
CT 
August 
26, 2024 
“Calpine’s Cumberland CT 1 generating facility in its current 
state will be physically unable to perform in the Delivery Year 
2027/2028 as a result of finalized regulations in connection 
with New Jersey’s efforts to limit carbon emissions from 
power plants.” 
Sherman 
Avenue 
August 
26, 2024 
“Calpine’s Sherman Avenue generating facility in its current 
state will be physically unable to perform in the Delivery Year 
2027/2028 as a result of finalized regulations in connection 
with New Jersey’s efforts to limit carbon emissions from 
power plants.” 
 
92 Vistra’s July 22, 2025, Deactivation Letter is available on the PJM Website.  See Deactivation Notice Letter 
for Kincaid Generation, L.L.C, from Jessica H. Miller, Vice President & Assoc. Gen. Counsel, Vistra Corp., to 
PJM 
Generation 
Manager 
(July 
22, 
2025), 
https://www.pjm.com/-/media/DotCom/planning/gen-
retire/deactivation-notices/kincaid-deactivation-letter.pdf.

37 
Elwood 
May 28, 
2024 
“Given current and expected market conditions and ongoing 
Illinois regulatory uncertainty, operation of Elwood is 
expected to continue to be uneconomic.”  
Fisk 
June 30, 
2026 
“Pursuant to the Illinois Climate and Equitable Jobs Act 
(“CEJA”), the Units are required to “permanently reduce all 
CO2e and copollutant emissions to zero, including through 
unit retirement” by January 1, 2030. As such, MWG intends to 
retire the Units on January 1, 2030.”  
Elgin 
May 10, 
2024 
“MRP Elgin is planning to retire the Units as of June 1, 2025 
in light of PJM market conditions and operating restrictions 
imposed by the stringent emissions limits under the Illinois 
Climate and Equitable Jobs Act. Given these circumstances, 
continued operation of the Units is expected to be uneconomic 
relative to other opportunities.” 
Zion  
June 22, 
2026 
“Constellation intends to retire these units in compliance with 
the Illinois Climate and Equitable Jobs Act (CEJA), which 
requires certain electric generation resources to reduce all 
CO2 and co-pollutant emissions to zero, including through 
unit retirement, on or before January 1, 2030.” 
Sayreville 
December 
29, 2023 
“The New Jersey Department of Environmental Protection 
(NJDEP) issued a final regulation on January 3, 2023 
establishing CO2 emissions rates limits for in-state electric 
generating units (EGUS) sized 25 MW and larger. The 
Sayreville units are unable to operate within the limitation that 
go into effect on June 1st, 2024, 1,700 lbs CO2/MWh. These 
new regulations will require New Jersey-located EGUs to 
retire if they are unable to meet the established CO2 emissions 
rates limits unless granted a reliability extension by the 
NJDEP.” 
Brandon 
Shores  
April 6, 
2023 
“The Brandon Facilities’ National Pollution Discharge 
Elimination System (“NPDES”) permit precludes operation 
using coal on or after January 1, 2026. Brandon had 
previously been evaluating a conversion of the Brandon 
Facilities to fuel oil combustion but has determined that, 
under current capacity market rules, such a conversion is 
uneconomic and does not justify operating after June 1, 2025. 
The Brandon Facilities have capacity market obligations 
through May 31, 2025.” 
H.A. Wagner  October 
16, 2023 
“The Wagner Facilities’ Title V air permit limits operation to 
capacity factors under 15% when operating on oil. The limited 
run hours on the Wagner Facilities are not sustainable to 
continue operations, especially in light of the amount of time 
the Wagner Facilities have recently been running in the 
market. The combination of low margin energy market

38 
economics, low-capacity prices and significant Capacity 
Performance penalty risk due to run hour limitations results in 
the economics being outweighed by the risk associated with 
continued operation. The Wagner Facilities have capacity 
market obligations through May 31, 2025.” 
Cardinal 
July 22, 
2026 
“[U]nless and until such conditions are satisfied, or waived by 
Buckeye in its discretion, continued operations past December 
31, 2028, will not be possible based on the requirements of the 
EPA NOPP and the Sierra Club Agreement. Should these 
conditions be satisfied, or waived by Buckeye in its discretion, 
Buckeye reserves the right to withdraw its deactivation notice 
and participate in future PJM capacity auctions for the 
2029/2030 Delivery Year and thereafter.” 
University 
Park North 
Station 
June 30, 
2026 
“LSPUP is deactivating these units due to uneconomic 
compliance requirements of the Illinois Climate and Equitable 
Jobs Act.”  
Rocky Road 
February 
6, 2026 
“Dairyland intends to retire the Unit due to its inability to 
meet operational restrictions imposed on the Unit by the Clean 
Air Act Permit Program (“CAAPP”) permit issued by the 
Illinois Environmental Protection Agency (“EPA”).” 
Forked River 
1 
February 
24, 2025 
“Forked River’s Unit-1 generating facility in its current state 
will be physically unable to perform in the Delivery Year 
2027/2028 as a result of finalized regulations in connection 
with New Jersey’s efforts to limit carbon emissions from 
power plants. Thus, as affirmed by this submission, Forked 
River plans to retire the Unit-1 generating facility before the 
commencement of the 2027/2028 delivery year and provides 
this Notice of Deactivation.” 
Forked River 
2 
February 
24, 2025 
“Forked River’s Unit-2 generating facility in its current state 
will be physically unable to perform in the Delivery Year 
2026/2027 because of its inability to meet NJ air permit 
requirements. Thus, as affirmed by this submission, Forked 
River plans to retire the Unit-2 generating facility before the 
commencement of the 2026/2027 delivery year and provides 
this Notice of Deactivation.” 
 
Given the outsized role that prospective assumptions regarding the future applicability 
of operational and environmental policy play in Deactivation decisions in the PJM Region, the 
stability and veracity of those assumptions are, by extension, critical to the determination of 
whether or not a Deactivation decision is efficient for the market and economic for the resource

39 
owner in the context of RPM’s three-year forward period.  And therein lies the problem.  Given 
the protean nature of the operational uncertainties and environmental policy considerations 
described above, a three-year forward period is often too long for resource owners to develop 
confidence that they will be permitted to continue operation of their Capacity Resources in the 
future.  The decision these resource owners are left with in light of that ambiguity is simple—
exit the market to avoid significant and hard-to-predict regulatory risks, even if it might 
otherwise be efficient for the market and economic for the resource owner to stay. 
Importantly, the uncertainty in operational availability and environmental policy 
described above also incentivizes the owners of Capacity Resources that remain in the market 
to include a “risk premium” in their RPM offers, especially when the auction is run three years 
forward.  As Dr. Nicholson explains, under PJM’s Capacity Performance construct, this 
uncertainty is reflected in a resource’s CPQR component of a capacity sell offer, meaning that 
the three-year forward period directly inflates the risk premium that owners of resources near 
the end of their economic life must build into their capacity supply offers, or exit the market 
rather than attempt to price that risk at all.93  This dynamic is not unique to PJM.  As ISO-NE 
explained in proposing a prompt capacity auction, “the uncertainty about whether a new or 
existing resource will be available to perform three years into the future can be reflected in 
suppliers’ capacity offers or bids through higher risk premiums, increasing Capacity Clearing 
Prices over what those prices would have been had the auction been held closer in time to the 
Capacity Commitment Period, where sellers would have more certainty about their 
performance and the costs associated with holding an obligation.”94 
 
93 Nicholson Affidavit, at ¶¶ 40-43. 
94 Id. at ¶ 41 & n. 63 (citing ISO-NE Transmittal, Docket No. ER26-925, at 24 (December 30, 2025)).

40 
In summary, the current three-year forward period inhibits efficient resource exit and 
Deactivation, as it requires generation owners to take on capacity commitments and make 
capital investments in the absence of reasonable predictability in future operational capability 
and environmental policy.  It also leads to higher capacity prices by causing the owners of 
Capacity Resources to include a “risk premium” in their RPM offers to account for these 
uncertainties. 
iv. 
PJM’s current capacity accreditation methodology (ELCC) bears no 
resemblance to the eFORd model considered by the Commission in 
2006, and the three-year forward period forces PJM to integrate 
speculative assumptions into its ELCC modeling. 
At the time of the Commission’s 2006 approval of RPM’s multi-year forward period, 
PJM used a capacity accreditation methodology known as Equivalent Forced Outage Rate - 
demand, or “eFORd.”  This methodology focused on historic, unit-specific metrics that 
measured the percentage of time that a specific unit was forced out of service or unable to run 
when called upon.  For various reasons, including the nature of the then-prevailing generation 
mix and the types of operational risks faced by the PJM Region, eFORd was supportable when 
RPM was accepted.  Additionally, because eFORd relied on a resource’s own historical 
performance rather than on system-wide, forward-looking modeling of the resource mix, it had 
a high level of predictability, stability, and replicability for resource owners. 
On July 30, 2021, the Commission accepted PJM’s proposal to transition from eFORd 
to a new capacity accreditation methodology, known as Effective Load Carrying Capability  
(“ELCC”).95  Unlike eFORd, ELCC considers the simultaneous reliability contribution of all 
resources, and recognizes the complementary and antagonistic interactions among the 
 
95 PJM Interconnection, L.L.C., 176 FERC ¶ 61,056 (2021).

41 
resources expected to be able to provide capacity in a given Delivery Year.  In general, a 
resource that contributes a significant level of capacity during high-risk hours (i.e., hours with 
very high electricity demand and low resource output) will have a higher capacity value under 
ELCC than a resource that delivers the same generating capability but only during low-risk 
hours.  These risk hours may vary as the resource mix changes (e.g., more wind and solar 
resources are installed) and hours of high demand evolve (e.g., wide-scale electric car charging 
at night).96   
As explained by Dr. Nicholson, the process by which PJM implements the ELCC 
model involves an extraordinary amount of data and analysis.97  Specifically, ELCC class 
accreditations are derived from sophisticated probabilistic modeling that estimates each 
resource class’s reliability contribution across a wide range of system conditions, placing the 
greatest weight on the hours of greatest reliability risk, and PJM must update and re-run this 
analysis as the assumed resource mix and load profile change from year to year.98 
Given the volume of data and analytical complexity involved in implementing the 
ELCC model, the accuracy and replicability of PJM’s ELCC model has remained an issue of 
paramount concern within the PJM Region since the model’s inception in 2021.  These 
concerns have been expressed directly to the PJM Board by the Organization of PJM States, 
Inc. (“OPSI”), with OPSI arguing that “[t]he accuracy of the ELCC methodology is essential 
and necessary to ensure that it reflects the true ability of supply to meet demand and secure the 
 
96 PJM’s current ELCC methodology is set forth in RAA, Schedule 9.2 and implemented through PJM Manuals 
21A and 21B.  
97 Nicholson Affidavit, at ¶¶ 44-50. 
98 Id., at ¶ 47.

42 
reliability needs of the region.”99  Indeed, in its August 4, 2025, letter approving the Forecast 
Pool Requirement (“FPR”) and the Installed Reserve Margin (“IRM”) for the 2027/2028 
Delivery Year BRA, the PJM Board acknowledged that at the Markets and Reliability 
Committee (“MRC”) and Members Committee (“MC”) “[a]dditional concerns were expressed 
about the methodology utilized to determine Effective Load Carrying Capability (ELCC) 
values that are derived from the same reliability analysis that produces the FPR and IRM.”100  
The Board accordingly directed PJM to engage a consultant to examine the ELCC 
methodology to identify improvements.  The consultant’s report was published in December 
2025,101 and included multiple recommendations regarding how to enhance transparency and 
accuracy.  
Yet the current three-year forward period of RPM works against model accuracy and 
replicability by forcing PJM to integrate assumptions that are almost certain to change over the 
course of three years.  As explained by Dr. Nicholson, under ELCC PJM must estimate the 
resource mix that will actually be available during the Delivery Year (including the mix of 
thermal, intermittent, and storage resources expected to be in service, and the retirements and 
new entry assumed to occur before that year) approximately three and a half years before the 
start of the Delivery Year, because capacity suppliers must know their accreditation values 
 
99 Letter from Emile Thompson, President, Org. of PJM States, Inc., to David Mills, Chair, PJM Bd. of Managers, 
& Manu Asthana, President & CEO, PJM Interconnection, L.L.C.,  at 2 (Aug. 28, 2025), https://www.pjm.com/-
/media/DotCom/about-pjm/who-we-are/public-disclosures/2025/20250828-opsi-letter-re-consultant-review-of-
elcc-methodology.pdf. 
100 Letter from David E. Mills, Chair, PJM Bd. of Managers, to PJM Stakeholders, at 1 (Aug. 4, 2025),  
https://www.pjm.com/-/media/DotCom/about-pjm/who-we-are/public-disclosures/2025/20250804-board-
correspondence-re-irm-and-fpr.pdf. 
101 Energy+Environmental Economics, PJM ELCC/ RRS Model Evaluation: Prepared for PJM (Dec. 2025),  
https://www.pjm.com/-/media/DotCom/committees-groups/task-forces/elccstf/2025/20251209/20251209-item-
02---pjm-elcc-rrs-model-evaluation---e3-report.pdf.

43 
before the BRA.102  These assumptions are far from static: PJM’s own preliminary ELCC 
estimates show that accreditation values for a given resource class can shift materially from 
one year’s estimate to the next, with storage resource ELCC values in particular projected to 
decline significantly across upcoming Delivery Years as PJM’s assumptions about extended 
cold-weather charging constraints evolve, and with the gas combustion turbine reference class 
also experiencing meaningful changes.  This dynamic can be seen in Figure 4 of the Nicholson 
Affidavit, which shows the final ELCC values for Delivery Years 2028/2029 and 2029/2030 
along with PJM’s preliminary estimate for Delivery Years 2030/2031 and 2031/2032.  
Nicholson Affidavit - Figure 4  
Actual and Preliminary ELCC Values, Delivery Years 2028/29 Through 2032/33 
 
Figure 4 of the Nicholson Affidavit illustrates just how much projected and actual 
ELCC values can change over the three-year forward period of RPM depending on the 
 
102 Nicholson Affidavit, at ¶ 46. 
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
2028/29
2029/30
2030/31
2031/32
2032/33
Preliminary ELCC calculation
Delivery Year
4-hr Storage
6-hr Storage
8-hr Storage
10-hr Storage
Gas CC
Gas CT

44 
assumptions used, such as the assumed resource mix and system loads.  Because even modest 
shifts in ELCC accreditation can translate into substantial swings in a resource’s qualifying 
capacity, and, in the aggregate, in the auction’s supply curve and clearing price, basing those 
accreditation values on three-and-a-half-year-old assumptions introduces significant 
inaccuracy into the BRA that a shorter forward period would not.103  Owing to the resulting 
inaccuracies, BRA prices can diverge from what underlying supply and demand fundamentals 
would otherwise produce, rendering the current three-year forward period unjust and 
unreasonable.  
v. 
The current three-year forward period undermines the accuracy of 
other BRA planning parameters, including the assumed resource mix in 
each Locational Deliverability Area used to calculate CETO/CETL 
values, leading to unjust and unreasonable results.  
The planning parameters used in a given BRA play a critical role in the auction’s 
outcome.  For example, RPM utilizes an administratively set demand curve—the Variable 
Resource Requirement Curve (“VRR Curve”)—which represents the prices that consumers 
should be willing to pay for varying quantities of capacity.   In developing the demand curve 
for a given BRA, PJM forecasts the expected peak load for a particular Delivery Year and then 
sets a target level of capacity needed to reliably serve the load—also known as the Reliability 
Requirement—given the expected resource portfolio.  The auction’s supply curve is based on 
Sell Offers for capacity that Capacity Market Sellers submit at a specific price and, together, 
the offers comprise the auction’s supply curve.  RPM is a locational market, meaning there are 
defined areas within the PJM Region that have limits on the amount of capacity they can 
import.  Those areas are LDAs, which recognize and quantify the locational value of capacity 
 
103 Id., at ¶¶ 46, 49-50.

45 
within the PJM Region.  As relevant here, the modeled LDAs are determined by comparing 
the import limit of an LDA (CETL) with the amount of capacity that needs to be imported into 
a LDA to meet the reliability criterion (CETO).  Sell Offers are located in specific LDAs based 
on where those resources are located. 
The accuracy of the planning parameters used in a given auction are only as good as 
the data upon which they are based.  As Dr. Nicholson explains, the three-year forward period 
undermines the accuracy of certain planning parameters, including CETO and CETL, because 
these values depend on assumptions about the resource mix and transmission topology that 
will actually exist in each LDA during the Delivery Year.104  As with the ELCC and load 
forecast inputs discussed above, these assumptions are far less reliable when projected three 
and a half years in advance than when set closer to the Delivery Year.  These inaccuracies and 
uncertainties introduced into the CETO and CETL parameters can, in turn, lead to capacity 
prices that do not reflect market fundamentals in the Delivery Year by misrepresenting the 
transmission system’s ability to transfer capacity.105  This can lead to unjust and unreasonable 
outcomes.  Indeed, the idea that inaccurate planning parameters can warp the outcome of a 
given BRA and disassociate it from basic market fundamentals is unfortunately not an 
academic one.  In December 2022, PJM discovered that certain Planned Generation Capacity 
Resources and planned Intermittent Resources in the DPL South LDA did not offer into the 
2024/2025 Delivery Year BRA, notwithstanding the fact that such resources were included by 
PJM years earlier in the modeling assumptions (CETO) that formed the DPL South LDA 
Reliability Requirement.  The absence of these resources from the 2024/2025 BRA resulted in 
 
104 Id., at ¶ 52. 
105 Id.

46 
an overstated LDA Reliability Requirement, and led to a dramatically higher clearing price 
that was wholly unrepresentative of the actual capacity needs of the LDA.106  As the 
Independent Market Monitor (“IMM”) described it, the clearing prices for DPL South “do not 
reflect the actual market supply and demand fundamentals, overstate the local reliability 
requirement, serve no useful purpose, and are therefore unjust and unreasonable.”107 
Accordingly, the three-year forward period of RPM is unjust and unreasonable, because 
it undermines the accuracy of important BRA planning parameters, including the assumed 
resource mix in each LDA used to calculate CETO/CETL values, leading to market outcomes 
divorced from underlying supply and demand conditions. 
B. 
The Commission Should Adopt a Prompt Auction Schedule as the Just and 
Reasonable Replacement Rate. 
In the event that the Commission finds the three-year forward period of RPM to be 
unjust, unreasonable, unduly discriminatory or preferential under FPA section 206, Exelon 
proposes the Commission direct PJM to adopt as a replacement rate a “prompt” BRA schedule, 
to run two months before a given Delivery Year, starting with the 2030/2031 Delivery Year 
BRA, currently scheduled for May 2027, and beyond.  The Commission need not treat this 
proposal as novel or untested.  To the contrary, the Commission has already found, on at least 
three occasions—for all of the other centralized capacity market structures in its jurisdiction—
that a prompt capacity auction schedule is just and reasonable.  Most recently, on March 30, 
2026, the Commission accepted ISO-NE’s proposal, filed jointly with the New England Power 
Participants Committee, to replace its three-year forward capacity market with a prompt 
 
106 See generally Docket No. ER23-729-000. 
107 PJM Interconnection, L.L.C., Comments of the Independent Market Monitor of PJM, Docket No. ER23-729-
000 (Jan. 20, 2023).

47 
capacity market in which an Annual Capacity Auction is held approximately one month before 
the relevant Capacity Commitment Period, effective March 31, 2026.108  In accepting ISO-
NE’s proposal, the Commission expressly relied on its prior orders finding that MISO’s prompt 
capacity auction schedule, under which MISO holds its auction two months before the delivery 
year, is just and reasonable.109  The Commission has likewise accepted prompt auctions relying 
on near-term procurement in NYISO.110  For the reasons discussed below, moving to a prompt 
schedule in PJM will provide the same substantial benefits, and particularly so in the dynamic 
and uncertain environment currently facing the PJM Region.  
i. 
A prompt auction will significantly improve the accuracy of key BRA 
auction parameters, resulting in capacity prices that better reflect 
actual supply and demand fundamentals and system conditions in the 
Delivery Year. 
A prompt auction schedule will significantly enhance the accuracy of key BRA auction 
parameters, thereby resulting in capacity prices that better reflect actual market fundamentals 
and system conditions in the Delivery Year.  As Dr. Nicholson explains, a shorter forward 
period would reduce forecast uncertainty across each of the BRA’s key inputs.  Specifically, it 
would allow PJM to forecast peak demand closer to the Delivery Year, reducing the risk of 
over-forecasting load and procuring more capacity than is actually needed, while also allowing 
PJM to base ELCC accreditation values on a resource mix and system conditions that are far 
more likely to reflect what will actually exist during the Delivery Year rather than a three-and-
 
108 See ISO-NE Order, at P 1.  
109 Id., at P 32 (MISO Order, at PP 70-74 (finding that MISO’s prompt capacity auction market design may be 
beneficial because “[load-serving entities] can accurately forecast their loads by taking into consideration changes 
such as those resulting from shifting economic conditions and MISO can accurately account for transmission 
constraints, forced outage rates, and expected performance of Load Modifying Resources”); MISO Rehearing 
Order, at PP 125-26).  
110 See N.Y. Indep. Sys. Operator, Inc., 179 FERC ¶ 61,102, at PP 2-3 (2022).

48 
a-half-year-old projection.111  It would also improve the accuracy of CETO/CETL values and 
the resulting Local Deliverability Area Reliability Requirements, which likewise depend on 
assumptions about the future resource mix and transmission topology.112 
The net effect of this enhanced accuracy in BRA auction parameters is self-evident—
capacity prices that better reflect actual market fundamentals and system conditions.  The 
Commission has previously found this policy outcome to be just and reasonable.  Specifically, 
in accepting ISO-NE’s prompt auction schedule, the Commission found that the shorter 
forward period would “reduce demand uncertainty because the Installed Capacity Requirement 
will be calculated using data that is closer in time to the Capacity Commitment Period” and 
would “result in more accurate Qualified Capacity values for resource accreditation.”113  
Similarly, in the Commission’s order accepting MISO’s prompt auction schedule as just and 
reasonable, the Commission found that “MISO’s prompt Auction design allows load 
forecasting to occur within the year leading up to the Planning Year.”114  The Commission 
acknowledged the inherent benefits of this change, finding that “LSEs can accurately forecast 
their loads by taking into consideration changes such as those resulting from shifting economic 
conditions and MISO can accurately account for transmission constraints, forced outage rates, 
and expected performance of Load Modifying Resources.”115   
 
111 Nicholson Affidavit, at ¶¶ 54-55. 
112 Id., at ¶ 56. 
113 ISO-NE Order, at P 32 (citing to ISO-NE Transmittal, at 23-30).  
114 MISO Order, at PP 70-74 (finding that MISO’s prompt capacity auction market design may be beneficial 
because “[load-serving entities] can accurately forecast their loads by taking into consideration changes such as 
those resulting from shifting economic conditions and MISO can accurately account for transmission constraints, 
forced outage rates, and expected performance of Load Modifying Resources”); MISO Rehearing Order, at PP 
125-26.  
115 MISO Order, at PP 70-74.

49 
The same legal and policy rationale the Commission used in the ISO-NE Order and the 
MISO Order apply with equal if not greater force here.  The closer in time that PJM establishes 
its Installed Reserve Margin, ELCC accreditation values, CETO/CETL, and other key BRA 
auction parameters to the actual Delivery Year, the more those parameters will reflect the 
resource mix, load conditions, and system topology that actually exist, rather than a years-old 
projection of what they might be.  These rationales are only strengthened by the rapidly 
changing conditions currently facing the PJM Region; that is, the demands of large loads and 
associated forecasting challenges, as well as the evolving resource mix and a shifting policy 
environment.   
ii. 
A prompt auction will significantly enhance the quality of information 
and the accuracy of the price signal used in generator Deactivation 
decisions.  
By definition, a prompt auction schedule narrows the window across which resource 
owners must attempt to forecast future operational, environmental, regulatory, and market 
conditions when deciding whether and how to bid into a BRA and commit their Capacity 
Resources for a Delivery Year.  As explained by Dr. Nicholson, this in turn enhances the 
quality and accuracy of the price signal that RPM sends to those resource owners in two distinct 
ways.116   
First, it increases the economic efficiency of resource exit from the market.  This 
enhanced efficiency in market exit will become increasingly important in the PJM Region in 
the coming years, as a substantial volume of existing capacity in the PJM Region is expected 
to reach the end of its useful life and retire.117  Some aging capacity has been kept operational 
 
116 See Nicholson Affidavit, at ¶ 57. 
117 Id.; See also PJM White Paper, at 16.

50 
in response to high prices.  Additional capacity has been kept operational by out-of-market 
mechanisms, such as RMR arrangements and FPA section 202c orders from the Department 
of Energy, but these interventions are, by definition, temporary and not designed as primary 
tools to achieve long-term resource adequacy.  Furthermore, as generating assets continue to 
age, keeping them operational will become prohibitively expensive, their operations will 
become even more challenging, and the resulting policy goal should be to manage their exit, 
not keep them online indefinitely.  To this point, the Commission has previously found 
proposals that increase the efficiency of economic market entry and exit to be just and 
reasonable.118   
Second, a prompt auction allows resource owners that choose to remain in the market 
to “de-risk” their capacity supply offers by removing the need to price in the multi-year 
“operational and policy-uncertainty” premium described above in Section IV.A.iii.119  This 
should apply downward pressure to capacity prices. 
In short, the shift to a prompt structure will significantly enhance the quality of 
information and the accuracy of the investment signal used in resource owner market exit and 
Deactivation decisions.  Specifically, a prompt structure will allow commitment decisions to 
be based on more current information, which will allow resource owners to better assess a 
Capacity Resource’s remaining economic life, operating condition, needed capital 
 
118  See e.g. Midcontinent Independent System Operator, Inc., 187 FERC ¶ 61,102, at P 80 (2024) (finding MISO’s 
RBDC proposal to adopt a sloped demand curve in the Auction to be just in reasonable in part because it will 
result in capacity price signals that will “provide better incentives for efficient resource entry and exit,” among 
other reasons), modified on denial of reh’g by Midcontinent Independent System Operator, Inc., 189 FERC P 
61159 (2024); ISO New England, Inc., 173 FERC ¶ 61,161, at PP 48–50 (2020) (agreeing on rehearing that a 
capacity market design “appropriately allows the [Forward Capacity Market] to provide the proper price signal 
to trigger entry and exit of capacity supply resources,” and finding that the Commission had properly “considered 
... whether the [Forward Capacity Market] provides the proper price signals to trigger appropriate entry and exit 
of capacity resources”).  
119 Nicholson Affidavit, at ¶ 57.

51 
improvements, and market risks (e.g., Capacity Performance risk), producing in aggregate 
outcomes that better reflect the actual state of the PJM fleet as it ages, and capacity prices that 
more accurately reflect the avoidable going forward costs of resources.   
iii. 
A prompt auction schedule will significantly enhance the quality of data 
used in PJM’s ELCC capacity accreditation, thereby better aligning 
both price and payments with resource contributions to resource 
adequacy. 
Another important benefit to a prompt auction schedule is the enhanced quality of the 
data inputs used in PJM’s ELCC capacity accreditation process.  PJM’s capacity accreditation 
methodology has grown substantially more complex and data-intensive since the Commission 
first approved the current multi-year forward period in 2006.  As noted above, in 2021 the 
Commission approved PJM’s transition from its longstanding eFORd methodology to an 
ELCC approach.  In 2024 the Commission accepted PJM’s proposal to make further 
enhancements by transitioning to a “marginal” ELCC framework and extending ELCC 
accreditation to all Generation Capacity Resources.  In doing so, the Commission 
acknowledged a key underlying concern with ELCC in relation to the RPM’s three-year 
forward period—namely that “PJM’s RPM aims to ensure resource adequacy for a future 
delivery year, and as such, there will inevitably be differences between the resource mix 
forecasted at the time of the auction and the actual, cleared resource mix.”120  Nonetheless, the 
Commission found that PJM had demonstrated that any differences between the forecasted and 
cleared resource mix are unlikely to introduce significant capacity accreditation errors.121  
Specifically, the Commission found that, based on PJM’s sensitivity analysis at the time, the 
forecast error was likely to be a “negligible amount” (an estimated 115 MW out of a 170,000 
 
120PJM Interconnection, L.L.C., 186 FERC ¶ 61,080, at P 75 (2024).  
121 Id., at P 76.

52 
MW system).122  As discussed above in Section IV.A.iv, data over the last two years has 
disproven this assumption.123   
Adopting a prompt auction will significantly improve the quality of data used in PJM’s 
ELCC modeling, thereby better addressing the Commission’s original concern in 2024 
regarding the “differences between the resource mix forecasted at the time of the auction and 
the actual, cleared resource mix.”124  As Dr. Nicholson explains, because a prompt auction 
would base ELCC accreditation on a resource mix and system conditions far closer to the actual 
Delivery Year, this will lead to superior economic outcomes by reducing both over- and under-
accreditation of resources and the resulting mispricing of capacity.125  Indeed, the Commission 
has already found that a prompt auction schedule produces more accurate capacity 
accreditation values, including in the ISO-NE Order where the Commission found as just and 
reasonable a prompt auction schedule that would “result in more accurate Qualified Capacity 
values for resource accreditation.”126 
Finally, a prompt auction schedule will allow Capacity Resources that have previously 
received a capacity commitment to have their accreditation values recalculated annually, using 
more up-to-date data.  This provides several benefits, including ensuring that a resource’s 
accredited capacity value reflects the resource mix and system conditions that actually prevail 
closer to the Delivery Year, rather than a three-and-a-half-year-old projection, giving resource 
 
122 Id.  
123 See Nicholson Affidavit, at ¶¶ 44-50. 
124 See PJM Interconnection, L.L.C., 186 FERC ¶ 61,080 (2024) (approving PJM’s transition to a marginal ELCC 
framework and acknowledging that the resource mix forecasted at the time of the auction will inevitably differ 
from the actual, cleared resource mix).  
125 Nicholson Affidavit, at ¶ 58. 
126 ISO-NE Order, at P 32.

53 
owners better information with which to construct their capacity supply offers and plan 
maintenance and retirement decisions, and reducing the risk that a resource is over- or under-
credited relative to its true reliability contribution. 
iv. 
A prompt auction will significantly reduce the risks to new resources 
seeking to enter the market by creating more certainty regarding their 
expected availability for the Delivery Year. 
A prompt auction will significantly reduce the risks, for customers and suppliers, 
associated with the timing of new resources entering the market, as resources will have more 
certainty about their expected availability for each Delivery Year, and particularly their first 
Delivery Year in service.  This will directly address the problem that the Commission has 
previously described as “phantom entry,” where resources that receive a capacity commitment 
years in advance are not actually operational in time for the delivery period.127  As the Filing 
Parties explained in the ISO-NE proceeding, this phantom entry problem can raise capacity 
prices when the risk of non-commercial operation is priced into capacity offers.128 
As explained by Dr. Nicholson, to the extent that it exists in PJM, a prompt auction 
would directly address the problem of “phantom entry” by allowing only those resources that 
have actually achieved, or are on the imminent path to achieving, commercial operation to 
participate, rather than requiring new entrants to make a binding capacity commitment years 
before they can demonstrate they will actually be available.129  This will provide both PJM and 
Market Participants with far greater certainty regarding actual resource availability for the 
applicable Delivery Year. 
 
127 See ISO-NE Order, at PP 13, 32. 
128 Id., at P 13.  
129 Nicholson Affidavit, at ¶ 59.

54 
V. 
REFUND EFFECTIVE DATE 
As discussed above, Exelon respectfully requests that the Commission establish a 
refund effective date of January 1, 2027, and permit Fast Track processing under Rule 206(h) 
to facilitate a Commission order by no later than January 31, 2027—currently the last day 
before the posting of the planning parameters for the 2030/31 Delivery Year BRA.   
VI. 
RULE 206 REQUIREMENTS  
To the extent not already provided above, Exelon provides the following additional 
information required by Rule 206 of the Commission’s Rules of Practice and Procedure.130  
Exelon respectfully requests waiver of any part of the Commission’s regulations necessary to 
process this filing. 
A. 
Good faith estimate of financial impact or harm (Rule 206(b)(4)) 
The complaint sets forth in detail above the financial impact and harm to PJM Market 
Participants caused by the three-year forward period of RPM.   
B. 
Practical, operational, or nonfinancial impacts (Rule 206(b)(5)) 
The practical, operational, and nonfinancial impacts of the RPM’s three-year forward 
period are described at length in the sections above. 
C. 
Whether the matters are pending in any other FERC proceeding or other 
forum (Rule 206(b)(6)) 
The issue of whether the three-year forward period of RPM has become unjust and 
unreasonable under FPA section 206, as presented in this complaint, is not to Exelon’s 
knowledge pending in any other existing Commission proceeding or forum in which Exelon is 
a party. 
 
130 18 C.F.R. § 385.206.

55 
D. 
Specific relief or remedy requested (Rule 206(b)(7)) 
The complaint sets forth in detail the specific relief requested. 
E. 
Documents supporting the complaint (Rule 206(b)(8)) 
This filing consists of the following: 
• This Transmittal Letter;  
• Affidavit of Dr. Emma Nicholson, included as Attachment A;  
• Affidavit of Deborah M. Sears, included as Attachment B; and 
• A Form of Notice, included as Attachment C. 
F. 
Use of alternative dispute resolution (Rule 206(b)(9)) 
Exelon has not used the Enforcement Hotline, Dispute Resolution Service, tariff-based 
dispute resolution mechanisms, or other informal dispute resolution procedures, because the 
complaint argues that the three-year forward period of RPM is no longer just and reasonable, 
and is therefore unlawful under FPA section 206.  Only the Commission has the legal authority 
to provide the statutory remedy that the complaint requests.  For this reason, Exelon does not 
believe that alternative dispute resolution (“ADR”) under the Commission’s supervision could 
successfully resolve the complaint, nor could any specific ADR procedures.  Exelon has not 
agreed to any process for resolving the complaint outside of the instant proceeding. 
G. 
Notice (Rule 206(b)(10))  
Exelon has appended a form of notice of this filing for publication in the Federal 
Register, in accordance with the specifications in section 385.203(d) of the Commission’s 
rules.  
H. 
Request for Fast Track Processing (Rule 206(b)(11)) 
As described above, Exelon respectfully requests that the Commission permit Fast 
Track processing under Rule 206(h) to facilitate a Commission order by no later than January

56 
31, 2027—currently the last day before the posting of the planning parameters for the 2030/31 
Delivery Year BRA.   
VII. 
SERVICE AND NOTICE 
In accordance with Rule 206(c), Exelon has served a copy of this complaint upon PJM, 
as Respondent, simultaneously with the filing of the complaint. 
VIII. CONCLUSION 
Wherefore, for the foregoing reasons, Exelon respectfully requests that the 
Commission: (i) find under FPA section 206 that the current three-year forward period of 
PJM’s RPM is no longer just and reasonable; (ii) adopt as a replacement rate a “prompt” 
auction schedule, to run two months before a given Delivery Year, starting with the 2030/2031 
Delivery Year and continuing beyond; (iii) establish a refund effective date of January 1, 2027; 
and (iv) permit Fast Track processing under Rule 206(h) to facilitate a Commission order by 
no later than January 31, 2027—currently the last day before the posting of the planning 
parameters for the 2030/31 Delivery Year BRA.

57 
Respectfully submitted, 
/s/ Jordan Kwok 
/s/ Thomas S. DeVita 
Jordan Kwok 
Thomas S. DeVita 
Director, Federal Regulatory Affairs 
Kimberly B. Frank 
Exelon Corporation 
Stuart B. Robbins 
701 Ninth Street, N.W. 
K&L Gates LLP 
Washington, D.C. 20068 
1601 K Street, NW 
(667) 313-0421 
Washington, DC  20006 
jordan.kwok@exeloncorp.com 
(202) 778-9000 
 
thomas.devita@klgates.com 
/s/ Alejandro Bautista 
kimberly.frank@klgates.com 
Alejandro Bautista 
stuart.robbins@klgates.com 
Assistant General Counsel 
 
Exelon Corporation 
Counsel for Exelon Corporation  
2301 Market Street 
 
Philadelphia, PA 19101 
 
(267) 533-0120 
 
alejandro.bautista@exeloncorp.com 
 
 
 
 
Dated: November 3, 2026

58 
CERTIFICATE OF SERVICE 
I hereby certify that I have on this date caused a copy of the foregoing document to be 
served upon PJM Interconnection, L.L.C., at the following addresses obtained from the 
Commission’s list of corporate officials designated to receive services pursuant to 18 C.F.R. § 
385.2010(k):  
Jessica M. Lynch 
Associate General Counsel 
PJM Interconnection, L.L.C. 
2750 Monroe Blvd. 
Audubon, PA 19403 
(267) 563-3688 
FERCeService@pjm.com  
Mark J. Stanisz 
Associate General Counsel 
PJM Interconnection, L.L.C. 
2750 Monroe Blvd. 
Audubon, PA 19403 
(610) 666-4707 
FERCeService@pjm.com   
 
Dated: November 3, 2026 
 
/s/ Stuart B. Robbins  
Stuart B. Robbins  
K&L Gates LLP 
1601 K Street, NW 
Washington, DC  20006 
(202) 778-9148 
stuart.robbins@klgates.com  
 
Counsel for Exelon Corporation