ER26-3380-000 · 2026-08-21 · Monitoring Analytics, LLC

Protest of the Independent Market Monitor for PJM re PJM Interconnection, LLC's 07/31/2026 proposed Reliability Backstop Procurement filing

UNITED STATES OF AMERICA 
BEFORE THE 
FEDERAL ENERGY REGULATORY COMMISSION 
 
PJM Interconnection, L.L.C. 
) 
) 
) 
 
 
Docket No. ER26-3380-000 
PROTEST OF THE INDEPENDENT MARKET MONITOR FOR PJM 
Pursuant to Rule 211 of the Commission’s Rules and Regulations1 Monitoring 
Analytics, LLC, acting in its capacity as the Independent Market Monitor (“Market 
Monitor”) for PJM Interconnection, L.L.C. (“PJM”),2 submits this protest to the filing 
submitted by PJM Interconnection, L.L.C. (“PJM”) on July 31, 2026, proposing (at 1) “to 
establish the Reliability Backstop Procurement (“RBP”)—a one-time procurement of new 
capacity to address resource adequacy challenges in the PJM Region arising from 
insufficient commitments of capacity in the 2027/2028 and 2028/2029 Reliability Pricing 
Model (“RPM”) Auctions, primarily driven by the unprecedented addition of large loads, 
most notably data centers” (“RBP Filing”).3  
The RBP Filing has not been supported as just and reasonable, and it should be 
rejected. The RBP Filing is unjust and unreasonable, and attempting to implement it will 
 
1 
18 CFR § 385.211 (2026). 
2 
Capitalized terms used herein and not otherwise defined have the meaning used in the PJM Open 
Access Transmission Tariff (“OATT”), the PJM Operating Agreement (“OA”) or the PJM Reliability 
Assurance Agreement (“RAA”). 
3  
The RBP Filing is supported by an (i) Affidavit of Ms. Danielle Croop on Behalf of PJM (Attachment 
C) (“Croop Affidavit”) and an (ii) Affidavit of Gwen Kelly on Behalf of PJM (Attachment D) (“Kelly 
Affidavit”).

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severely damage PJM markets, create unintended consequences, and compound that 
damage for a period of 15 years. 
The problem that the RBP Filing is designed to address is real and needs immediate 
action. The current rules are not designed to address the extraordinary circumstances that 
confront the PJM markets today. PJM has done nothing to prevent the interconnection of 
data centers that it does not have the capacity to serve. Timely action is needed to protect 
resource adequacy in the PJM Region while ensuring that data centers pay for the capacity 
they need and bear the risks they impose. There is broad agreement among policy makers, 
regulators, and developers, captured in the Ratepayer Protection Pledge and Principles, on 
the need to ensure that data centers bring their own new generation and pay their own way 
and to prioritize the protection of reliability and affordability for all the other customers.4 5 
 
4 
See 
The 
White 
House, 
“Ratepayer 
Protection 
Pledge” 
(March 
4, 
2026), 
<https://www.whitehouse.gov/releases/2026/03/ratepayer-protection-
pledge/?utm_source=wh_social_share_button>, Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, 
2026) (“Today, pursuant to the Ratepayer Protection Pledge, leading United States hyperscalers 
and AI companies guarantee that data centers’ energy needs will not increase household electricity 
costs for American citizens. Instead, these companies will build, bring, or buy the new generation 
resources and electricity needed to satisfy their energy demands, and pay for all new power 
delivery infrastructure upgrades to service their data centers. They will voluntarily negotiate new, 
separate rate structures with their utilities and relevant State governments, and pay those rates, and 
for their infrastructure, whether they use the electricity or not. They will also invest in local 
communities and coordinate with grid operators to contribute to a more reliable grid.”) (“Pledge”). 
On July 23, 2026, over 200 additional entities joined the pledge. See The White House, “President 
Trump’s Ratepayer Protection Pledge Secures American AI Dominance, Protects Consumers” (July 
23, 
2026), 
<https://www.whitehouse.gov/releases/2026/07/president-trumps-ratepayer-protection-pledge-
secures-american-ai-dominance-protects-consumers/?utm_source=wh_social_share_button>. 
5  
National Energy Dominance Council, Statement of Principles Regarding PJM (January 16, 2026) 
<https://www.energy.gov/documents/statement-principles-regarding-pjm> (“Principles”). Two principles 
apply to the contemplated procurement of new generation. First, the procurement should 
“[p]rovide 15-year price certainty for new capacity resources” [emphasis]. The statement notes that 
this can be done in through a “Reliability Backstop Auction,” but does not require that this auction 
be a centralized procurement by PJM or that PJM customers assume risks. Second, “PJM should 
allocate the cost of any new capacity through the aforementioned Reliability Backstop Auction to 
load serving entities (LSEs) with new data centers that have not self-procured new capacity or 
agreed to be curtailable.” The principles, agreed to by the Governors of PJM States Indiana, Ohio,

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The Pledge affirms: “The Ratepayer Protection Pledge and the commitments embodied 
therein effectuate the national policy of the United States.” The Commission has recognized 
the Pledge and Principles.6 The Pledge and Principles should guide the development of 
rules to support resource adequacy by procuring new capacity to serve data centers and 
ensuring that data centers pay for that capacity and that those costs are not assigned, 
allocated or otherwise pushed onto other customers. 
Accordingly, in addition to rejecting the RBP Filing as not shown to be just and 
reasonable, an order should issue, finding that the existing rules relating to resource 
adequacy for serving data centers in the PJM Region are unjust and unreasonable under 
Section 206 of the Federal Power Act.7 Upon issuing a finding that the current rules are 
 
 
Maryland Pennsylvania, Virginia, West Virginia, Delaware, Illinois, Michigan, New Jersey, 
Tennessee, North Carolina and Kentucky, call for PJM to do the allocation and to match data 
centers to the costs not excluding risks of new resources or commitments to curtail. Additional 
principles that going beyond the RBF Proposal, the Market Proposal, or potential alternatives, 
include: (i) extending the price collar for two additional RPM Base Residual Auctions, (ii) PJM 
improving load forecasting, (iii) accelerating generator interconnections, i.e., the Reliability 
Resource Initiative (RRI), and (iv) continued efforts to reform the capacity market. 
6  
See PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 at PP 2, 5, 8, 32 & 69 (2026) (“Large Load Show 
Cause Order”). The Large Loads Show Cause Order states (at P 66) (“We next preliminarily find 
that PJM’s Tariff appears to be unjust and unreasonable because it lacks adequate mechanisms to 
mitigate the risk of cost shifting among transmission customers, which may result in unjust and 
unreasonable rates for transmission service. In particular, we are concerned about the apparent lack 
of: (1) transparency regarding the assignment of Network Upgrades, and their associated costs, that 
are needed to provide transmission service to Eligible Customers on behalf of large loads; and (2) a 
pro forma cost recovery agreement between PJM, the relevant transmission owner, and the Eligible 
Customer taking transmission service on behalf of large loads that help ensure that Eligible 
Customers bear the risk and are ultimately responsible for costs incurred to provide transmission 
service, including the cost of Network Upgrades.”). 
7  
See 16 U.S.C. § 824e(a); see also Large Loads Show Cause Order at P 49 (“[W]e today exercise our 
authority to ensure that the process by which jurisdictional transmission providers and/or 
transmission owners will study the provision of jurisdictional transmission service to Eligible 
Customers on behalf of large loads interconnecting to the transmission system, including where, as 
allowed by state law or a public utility’s voluntary offer of such service, an end-use large load seeks 
unbundled retail transmission service, is just and reasonable and not unduly discriminatory or 
preferential. Pursuant to that authority, we find that PJM’s Tariff appears to be unjust and

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unjust and unreasonable, the Commission can, on the basis of the existing record, act 
without delay to direct PJM to immediately implement a remedy. 
A remedial order should direct that PJM file, withing two weeks, a solution with the 
following elements: 
• 
PJM should, working with LSEs and EDCs, immediately identify data center 
load not interconnected by June 1, 2026, and remove it from RPM capacity 
market auctions. 
• 
PJM should establish criteria to be included in the RAA defining the obligations 
of LSEs to require that new data center loads have 15 year bilateral contracts with 
new generation that do not permit any cost or risk shifting to other customers. 
The contracts would be based on general terms and conditions in accordance 
with tariff defined criteria with the cost and risk specifics defined by the data 
centers and generators.  
• 
For LSEs with data centers unable to make independent arrangements meeting 
the criteria, PJM should run a full single clearing price auction using the BRA 
capacity market clearing model for new data center load. LSEs would require 
data centers to participate in the reliability backstop auction if they do not have a 
bilateral contract for new generation that meets the requirements of such 
contracts. When the clearing process is complete, the LSEs would require that 
generators and data center loads enter into 15 year bilateral contracts that do not 
permit any cost or risk shifting to other customers. The contracts would be based 
 
 
unreasonable or unduly discriminatory or preferential because it lacks sufficiently clear and 
consistent provisions regarding the study process related to the provision of transmission service to 
Eligible Customers on behalf of large loads. We need not comprehensively address the 
Commission’s jurisdiction over other aspects of the addition of large loads to the transmission 
system at this time.”).

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on general terms and conditions in accordance with tariff defined criteria with 
the cost and risk specifics defined by the data centers and generators. 
• 
PJM should establish curtailment obligations for wholesale service to data 
centers during a defined transition period that would allow all data centers the 
time to contract for new generation. 
These requirements meet the goals of the Pledge and Principles and can be 
implemented immediately. 
I. PROTEST 
A. The RBP Filing Has Not Been Shown Just and Reasonable. 
PJM faces the issue of how to address the massive and unexpected influx of data 
center load. While data center growth has occurred over five or more years, PJM has failed 
to address the impact of data centers on the PJM Capacity Market over the last four capacity 
auctions. PJM has made its RBP Filing only under direct pressure from the Commission and 
the White House and the PJM governors, among others. It is clear that the current situation 
and the current tariff in PJM are untenable and therefore unjust and unreasonable. The 
addition of data center load has resulted in adding $29.4 billion to the cost of capacity, 
higher energy costs, higher transmission costs, and a significant degradation of system 
reliability. Rather than directly addressing the issue of data center load, PJM’s RBP Filing 
proposes an extremely complex approach to this issue that unnecessarily undermines basic 
elements of the PJM market design.  
PJM’s RBP Filing fails to explain why PJM does not directly address the data center 
issue. PJM’s RBP Filing fails to explain why PJM imposes the costs of data centers on other 
customers and does not require data centers to pay the costs and bear the risks that they 
impose on the system. PJM’s RBP Filing fails to explain why each of the significant changes 
to the fundamentals of the current capacity market design are required in order to address

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the data center issue. PJM fails to explain why the simple, focused Market Monitor proposal 
that was presented in stakeholder discussions should not be adopted.8 
PJM’s current approach to addressing data center load is not just and reasonable, as 
demonstrated by the results of the last four Base Residual Auctions. It is not the 
fundamentals of the capacity market design that are at issue. It is not the fundamentals of 
the energy market design that are at issue. It is the fact that PJM is currently allowing the 
rapid interconnection of large data center loads without having the capacity to serve those 
loads that makes the current PJM application of the rules unjust and unreasonable. The 
Market Monitor has demonstrated that PJM’s approach has created a massive financial 
burden on all PJM customers.9 10 That demonstration does not include the additional 
impact on energy market prices or on the costs of transmission. The RBP Filing in this 
matter further demonstrates PJM’s own belated recognition that the application of the 
current tariff rules is not just and reasonable. 
The RBP Filing is inconsistent with the purpose of the Ratepayer Protection Pledge 
and Principles. That purpose is to ensure that data centers pay for their own costs and risks. 
PJM’s proposed RBP auction defines a shortfall that is based entirely on data center load yet 
assigns the costs and risks associated with meeting that shortfall to other PJM customers. 
PJM’s mistake, in this filing, is to propose unsupported changes to the fundamental 
market design while ignoring the actual data center issue which is that the data center loads 
are imposing significant costs and risks on other customers. There is a straightforward 
 
8  
See IMM, CIFP: Reliability Backstop, “Proposed reliability backstop auction design” (v6) (June 30, 
2026), included as Attachment A. 
9  
See Monitoring Analytics, LLC “Analysis of the 2027/2028 RPM Base Residual Auction – Part A,” 
(January 5, 2026). 
10  
See Monitoring Analytics, LLC, 2026 Quarterly State of the Market Report for PJM: January through June 
(August 13, 2026) Section 1: Introduction.

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approach that directly addresses the data center issue while maintaining the current market 
design. 
PJM’s RBP Filing is inconsistent with PJM’s fundamental market design. The 
elements of PJM’s market design that PJM seeks to change protect the public interest and 
have worked to provide competitive results over a significant period. Additional rules are 
needed to address the extraordinary issues presented by the speed and size of data center 
additions. 
Federal and State government at the highest levels, with the explicit support of the 
data centers themselves, have identified the issues and have identified acceptable solutions. 
By their published standards, the RBP Filing is unacceptable. PJM’s RBP Filing violates the 
Ratepayer Protection Pledge and Principles because the RBP Filing assigns the costs and 
risks of data center load to other customers.  
These facts, separately or together, should result in Commission rejection of the PJM 
RBP Filing. PJM should be directed to file tariff modifications within two weeks that would 
create a reliability backstop auction that facilitates the acquisition of capacity for those data 
centers that commit to buying capacity and that have not otherwise bought capacity. 
The goal should be a practical, implementable method for helping data centers to 
acquire and pay for capacity in order to help PJM and LSEs’ meet their obligations to ensure 
system reliability in the face of a massive onslaught of data center load, while ensuring that 
data centers have access to power. 
B. The RBP Filing Is Deficient, Unjust and Unreasonable. 
1. The PJM RBP Filing would violate fundamental elements of the PJM 
capacity market design. 
The PJM RBP proposal would violate these fundamental elements of the PJM 
capacity market design: 
• 
Must buy/must sell requirements in the capacity market 
• 
LSEs’ role in the capacity market 
• 
Locational capacity market design

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• 
Single clearing price auction design 
• 
Market power mitigation rules 
• 
Responsibility for performance and for failure to perform 
2. PJM’s RBP Filing would reverse the core must buy/must sell 
obligations in the capacity market and convert to must buy/option to 
sell at highest price. 
The PJM capacity market design is a must buy/must sell design in which all LSEs 
and all capacity owners must participate.11 12 The existing symmetrical design was intended 
to counter the market power of generation owners while allowing all LSEs to meet their 
obligation to have capacity to cover their load obligations. The PJM RBP Filing would 
replace the must buy/must sell design with a must buy/option to sell at the highest price 
design. The proposed must buy/option to sell at the highest price design undoes the 
symmetry and creates market power for generation sellers. The proposed must buy/option 
to sell at the highest price design provides no choice for buyers, but forces LSEs to pay the 
prices that result from PJM’s RBP process that fails to include any market power mitigation 
rules. 
PJM has failed to provide any explanation for why they propose to undermine this 
core element of the capacity market and impose high prices on LSEs who have no ability to 
affect the price while allowing generators the option but not the obligation to sell at the 
highest price. 
 
11  
“Reliability Assurance Agreement Among Load Serving Entities in the PJM Region,” Article 7 § 7.2 
& Schedule 8. 
12  
PJM OATT Attachment DD § 6.6.

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3. PJM’s RBP Filing would inappropriately require LSEs to bear costs and 
risks. 
PJM’s RBP Filing is inconsistent with PJM’s fundamental market design because it 
would substitute a bilateral design for a competitive market design by making individual 
LSEs and their customers responsible for the costs of data center load. PJM’s repeated 
assertion that the PJM Capacity Market is primarily a bilateral market is not correct. That 
assertion is not supported by history. That assertion is not supported by the actual capacity 
market design and the actual functioning of the PJM Capacity Market.  
The capacity market was originally implemented in 1999 at the request of the 
Pennsylvania Public Utility Commission in order to prevent existing generation owners 
from exercising market power against new entrant competitive LSEs that needed to buy 
capacity to meet their reliability obligation as defined in the RAA. That market power could 
be exercised because the only source of capacity for a new entrant LSE to meet its reliability 
obligation was a bilateral contract with existing generation owners. Then, as now, the 
ownership of capacity was highly concentrated and the generation owners had the ability to 
exercise market power in those bilateral negotiations.  
The solution was a competitive capacity market that required all generation owners 
to sell their capacity at a competitive price and all LSEs to buy the capacity needed to meet 
their reliability requirements at a competitive price. The result was access to competitively 
provided capacity that permitted competitive new entrant LSEs to compete with the 
incumbent utilities to meet load. As the capacity market evolved into the RPM design, the 
PJM capacity market design remains a must buy/must sell design in which all LSEs and all 
capacity owners must participate.13 This design prevents both buyer side and seller side 
market power. 
 
13  
LSEs may elect the Fixed Resource Requirement (“FRR”) alternative. See “Reliability Assurance 
Agreement Among Load Serving Entities in the PJM Region,” Schedule 8.1.

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PJM’s RBP Filing assigns the costs and risks of data center load to LSEs and their 
other customers based on this bilateral view of the capacity market. PJM supports its use of 
a pay as bid auction design by asserting that it “more closely aligns with the economics and 
settlement structures of bilateral contracts.”14 PJM’s proposal would reverse the advantages 
of the competitive capacity market and restore market power by assigning the costs of the 
RBP procurement to LSEs based on their share of the shortfall in the 2028/2029 Delivery 
Year based on forecasted growth in the large loads.15 Data center loads are not the 
responsibility of the LSEs where the data centers choose to locate or of the other customers 
of the LSEs. Data center loads should pay their own costs and cover their own risks. PJM’s 
RBP Filing directly imposes the costs and risks of meeting data center load on LSEs and 
their customers. 
The assignment of costs to LSEs with data center load is also inconsistent with the 
Reliability Backstop Auction provisions of the tariff. The Reliability Backstop Auction tariff 
rules assign the costs of procuring backstop capacity to all LSEs in PJM on a pro rata basis 
based on their daily unforced capacity obligations. PJM’s RBP Filing did not change this 
language in Attachment DD, Section 16.4, as it applies to the Reliability Backstop Auction. 
4. The RBP Filing is inconsistent with the basic locational design of the 
PJM Capacity Market. 
The RBP Filing is inconsistent with the basic locational design of the PJM Capacity 
Market. The current locational Reliability Pricing Model (RPM) design was implemented in 
2007 because the capacity supply and demand conditions were very different by location 
within PJM. In 2007, the zones in Maryland and New Jersey were short capacity and 
western zones were long capacity and the transmission system did not permit the excess 
 
14  
Id. at 23–24. 
15  
Attachment A - Revisions to the PJM Open Access Transmission Tariff and PJM Reliability 
Assurance Agreement at 18.3 Cost Allocation of RBP Charges, Credits, and Shortfall Charges 
(“Attachment A – Marked Tariff Records”).

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capacity in the west to solve the issues in the east. Maryland and New Jersey faced 
reliability issues and western zones did not. PJM created the locational RPM design in 
response to these basic structural facts.  
PJM’s explicit and conscious and unsupported failure to include locational 
requirements in the RBP Filing creates the risk of repeating the experience of 2007. PJM’s 
failure to address locational issues risks customers having to pay higher capacity prices in 
price separated LDAs, customers having to pay for additional transmission and customers 
having to pay more for energy as more expensive local resources are required to actually 
meet the data center load rather than the resources acquired in the RBP. PJM’s assertion 
that it cannot predict CETO and CETL values for 15 years is irrelevant. That should not 
serve as a facile excuse for simply ignoring the critical locational dimension of the capacity 
market. Simply ignoring locational issues could result in very significant locational 
mismatches between resources and loads that are not resolvable even through transmission 
expansion. There are clear solutions available for addressing the locational facts of PJM 
including requiring that the generation to serve a data center must be in the same LDA as 
the data center. Ignoring locational realities is not an option. Ignoring locational realities 
will create unintended consequences including the need to build transmission in the future 
and price separation in the capacity market that could mean even higher capacity prices in 
areas with data center load. 
5. The RBP Filing abandons single clearing price auction in favor of pay 
as bid. 
The RBP Filing abandons the single clearing price auction design in favor of pay as 
bid, despite the complete failure to explain why economists’ consensus view of this issue is 
ignored.16 Pay as bid is inefficient and does not facilitate competition. After deciding to 
abandon basic competitive market design PJM then uses its chosen pay as bid structure as a 
 
16  
RBP Filing, Attachment C (Croop Affidavit) at 21.

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reason for failing to have market power mitigation rules. PJM fails to justify using pay as 
bid in place of the competitive and efficient single clearing price approach that has been a 
fundamental part of the PJM market design since its inception. 
Under PJM’s proposed pay as bid structure an RBP seller, if selected in the 
procurement process, will be paid its RBP sell offer. PJM also proposes to not use “market 
power screening or mitigation measures.”17 It should be unacceptable that PJM, at a time of 
severe supply shortage, would propose to not use the standard market power screening 
that is used in all PJM capacity auctions.  
Pay as bid auctions do not provide an incentive for sellers to reveal their costs while 
a uniform price auction does. For example, if Plant A has a lower cost than Plant B and both 
generators are expected to clear, under pay as bid Plant A has an incentive to offer above its 
actual cost and to guess at the clearing price. In a uniform price auction, Plant A can offer 
its cost and still receive the higher clearing price in the case that Plant B is marginal. That is 
the efficient and competitive outcome. By proposing a pay as bid auction design with no 
market power screening, RBP market sellers have a strong incentive to offer above their 
cost. PJM defends using pay as bid pricing rather than uniform pricing that is used in PJM’s 
RPM auctions by asserting that pricing outcomes are less likely to serve as market signals 
and that the pay as bid approach “more closely aligns with the economics and settlement 
structures of bilateral contracts.”18 PJM misses one of the important aspects of having a 
competitive capacity auction that reveals prices. Competitive auctions provide a price 
signal to both parties engaged in bilateral contract negotiations. Finally, PJM argues that 
uniform pricing would require offers to be normalized using potentially complex and 
subjective assumptions because the RBP capacity product is not uniform due to differences 
in contract duration, commercial operation dates, ELCC accreditation and changes in the 
 
17  
Id. at 32. 
18  
Id. at 23–24.

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ELCC accreditation over the 15 year period.19 The whole point of capacity accreditation and 
calculating a levelized cost offer is to provide a homogenous product at a comparable price 
that conveys all necessary information to the buyer and the buyer is indifferent between 
purchasing the product from Plant A versus Plant B. PJM’s own evaluation of which offers 
are better than others depends on calculating the price for a product. PJM is in fact using 
complex and subjective assumptions to evaluate competing offers. 
6. The PJM RBP Filing fails to address market power. 
The PJM RBP Filing explicitly and entirely fails to address market power despite the 
fact that the entire PJM Capacity Market is characterized by endemic market power and 
despite the fact that the RBP auction design creates market power by establishing an 
inelastic demand for capacity and a maximum price that is not really a maximum price. 
Effective market power mitigation is needed now more than ever. PJM’s only justification 
for failing to address market power is that it is difficult to design market power mitigation 
rules when there is a pay as bid design. The pay as bid design is PJM’s choice. PJM’s 
rationale for pay as bid is that it looks more like a bilateral market. PJM fails to note a key 
feature of bilateral markets. Bilateral markets have two sides. PJM’s RBP simply assigns 
costs to LSEs and gives LSEs no voice in the price. The result is not a bilateral market but a 
one sided market with extreme market power conferred on generators.  
PJM has chosen an inefficient and noncompetitive pay as bid design despite the 
nearly unanimous recommendation of economists that in turn makes market power 
mitigation more difficult. The answer is straightforward. Use a single clearing price auction 
with clear market power mitigation rules. 
 
19  
Id. at 25.

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7. The RBP Filing shifts ELCC risk from generators to customers. The RBP 
filing shifts the risks of generators failing to perform to customers. 
PJM’s RBP rules would permit generators to sell more capacity than they actually 
have and to do so without penalty for overstating capacity. PJM’s RBP rules allow RBP sell 
offer UCAP MW values up to 120 percent of the maximum preliminary ELCC class rating 
for 2028/2029 through the last posted Delivery Year.20 This will overstate the RBP cleared 
MW and require customers to pay for nonexistent capacity. More generally, PJM proposes 
to inappropriately shift ELCC related risk from generators to customers.21 Generator 
performance risk is an investor risk and not a customer risk. One of the benefits of markets 
is that performance risk is assigned to generators because they are responsible for unit 
performance. 
There is no analytical or market basis for permitting generators to oversell capacity 
in the RBP process. In fact, as PJM pointed out recently, increased data center load results in 
reduced ELCC values for most technology types.22 Regardless of expected ELCC changes, 
generators should sell only the amount of their current accredited capacity and generators 
should bear the risk of changes in accredited value. 
Under PJM’s RBP Filing, generators are not required to cover shortfalls due to 
changes in the ELCC ratings. The generators will not be paid for the shortfall in capacity 
but there are no shortfall charges for failing to provide what was sold.23 This shifts the 
 
20  
Attachment A – Marked Tariff Records at Attachment DD, 18.5(e)(i). 
21  
Shortfalls due to decreases in the ELCC ratings are not subject to RBP Shortfall Charges. See RBP 
Filing, Attachment A – Market Tariff Records, Attachment DD, 18.6(d).  
22  
Installed Reserve Margin (IRM), Forecast Pool Requirement (FPR), and Effective Load Carrying 
Capability (ELCC) for 2029/2030 BRA at 6 and 16, MRC Meeting Materials Item 3, Markets and 
Reliability 
Committee 
(August 
19, 
2026). 
<https://www.pjm.com/-/media/DotCom/committees-
groups/committees/mrc/2026/20260819/20260819-item-03---2029-2030-bra-irm-fpr---presentation.pdf> 
23  
RBP Filing, Attachment A – Market Tariff Records, Attachment DD, 18.6(c) through (d).

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ELCC accreditation risk to load which has to pay for the additional supply to cover the 
shortfall. This transfers the risk of non-delivery to the load and unfairly requires the load to 
pay for the shortfall in needed capacity rather than requiring the RBP seller to provide the 
capacity.  
8. The RBP Filing is inconsistent with the capacity market approach to 
penalties for performance. 
The RBP Filing is inconsistent with the capacity market approach to penalties for 
performance. 
RBP Shortfall Charges are defined in the PJM proposed Tariff, Attachment DD, 
Sections 18.6(c) through 18.6(e). PJM proposed Tariff, Attachment DD, section 18.6(d) states: 
RBP Resources with RBP UCAP MW committed through the 
Reliability Backstop Procurement that are unable to meet its full 
RBP UCAP MW commitment due to not achieving commercial 
operation by the first Delivery Year of the RBP commitment shall 
be subject to RBP shortfall charges for the committed RBP UCAP 
MW until the resources achieves commercial operation, for up to 
three years. 
This proposed Tariff language unnecessarily restricts the applicability of charges to a 
narrow, specific reason, is vague about the timing of the charges, limits the charges to three 
years, and shifts the risk from resource owners to customers. The PJM proposed criteria for 
defining RBP Shortfall Charges have not been shown to be just and reasonable and should 
be rejected. PJM’s proposed criteria for defining RBP Shortfall Charges are also vague and 
unenforceable. PJM has not explained why the RBP penalties vary so significantly from the 
current RPM rules. 
Deficiency charges in the current RPM rules are assessed due to a failure to satisfy a 
commitment “for any reason,” such as derates and retirements whereas the proposed RBP 
Shortfall Charge would only apply for a specific reason, “due to not achieving commercial

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operation.”24 For example, if a generation project configuration and MW change 
significantly but it still achieves commercial operation by the delivery year, it is not clear 
whether RBP Shortfall Charges would apply. If a generation resource achieves commercial 
operation but then has a catastrophic failure and retires halfway through the 15 year term, it 
appears that no RBP Shortfall Charges would apply.  
Use of the term commercial operation instead of the more precise tariff defined 
commencement of Interconnection Service limits the applicability even more so. Also, the 
term commercial operation is generally not a term applied to demand resources and DER 
aggregation resources. As RBP Resources under the PJM proposal include demand 
resources and DER aggregation resources, it is not clear how the RBP Shortall Charges 
would apply to these resource types. In fact, in defining the eligibility criteria for RBP 
Resources in proposed Tariff, Attachment DD, Sections 18.5(a)(i), PJM distinguishes 
demand resources and DER aggregate resources as being registered and under a contract to 
perform versus having a commercial operation date prior to June 1, 2032. PJM does not 
explain why this same distinction is not included in the RBP Shortfall Charge provision.  
PJM states that RBP Shortfall Charges would apply if commercial operation is not 
achieved by the first Delivery Year of the RBP commitment. PJM OATT, Attachment DD, 
Section 8 Capacity Resource Deficiency Charges, which is a parallel charge to the RBP 
Shortfall Charge, clearly states that the charge is applicable when committed MW are 
unable or unavailable to deliver unforced capacity “for all or any part of such Delivery 
Year” and likewise uses the term “start of the Delivery Year” when describing the timing of 
the failure to meet RPM commitments.25 The PJM proposed Tariff language lacks specificity 
in defining the timing of the penalty assessments. PJM does not explain or support the 
different treatment for RBP resources. 
 
24  
OATT Attachment DD § 8.1. 
25  
OATT Attachment DD § 8.

- 17 - 
Under the PJM proposal, the RBP Shortfall Charges are limited to three years. In the 
transmittal letter, page 61, PJM states that the reason for the limitation on the RBP Shortall 
Charges is to reduce barriers to entry. Limiting the penalties to three years of the 15 year 
term results in shifting the risk from resource owners to LSEs. PJM’s reasoning is not logical 
or meaningful. The fact that a generator in a market has risks is always a barrier to entry. 
Barriers to entry are not bad by definition. PJM’s entire tariff could be reasonably 
considered to be a barrier to entry. It is not PJM’s role to help generators by shifting their 
risks to customers. Yet that is exactly what PJM proposes to do. 
PJM proposed Tariff, Attachment DD, Sections 18.6(d)(i) states: 
An RBP Resource that is a generation or Energy Storage Resource 
and is unable to meet expected commercial operation date solely 
due to Network Upgrades shall be excepted from RBP shortfall 
charges if the RBP Resource successfully demonstrates readiness 
through test energy and seeks interim deliverability. 
This exception for unavailability due to Network Upgrades erodes the penalty 
assessment and again results in shifting the risk from resource owners to LSEs and their 
customers.  
The RBP Filing is also inconsistent with a logical approach to addressing the data 
center issues: 
• 
Fails to distinguish data center load from other loads 
• 
Fails to match energy supply and data center demand 
• 
Fails to provide revenue certainty for full generation revenue requirement 
• 
Fails to include a consistent definition of capacity that can meet data center 
load 
• 
Fails to include effective, targeted penalties for failure to perform 
• 
Fails to include a logical market clearing mechanism 
• 
Fails to update the maximum price used in the RBP 
• 
Fails to reasonably assign risk and the associated credit and collateral

- 18 - 
1. PJM proposes to include all large loads rather than just data center load. 
The ostensible goal of the RBP Filing is to address the data center issue. Addressing 
the data center issue requires separately identifying and providing special rules applicable 
to LSEs serving data center loads. Special rules are justified because there are extraordinary 
circumstances specifically applicable to data centers.26 Data centers are requesting 
unusually expedited service and at unusually elevated volumes, and significant efforts are 
being made to accommodate their extraordinary demands. Large loads in the nature of 
customers who have a long history of taking service from the system are not responsible for 
the data center issue. These customers are not seeking the sudden addition of large loads on 
an expedited basis outside of longstanding historical norms. It is necessary and appropriate 
to craft rules that specifically apply to LSEs serving data centers for the same reason that 
hyperscalers representing data centers are the ones affirming the Pledge. The inclusion of 
all large loads within the scope of the RBP Filing is unjust and unreasonable, and is unduly 
discriminatory, because large loads that are not data centers do not present the 
extraordinary circumstances that the RBP Filing should address. 
2. The RBP Filing fails to match supply and demand for energy 
The RBP Filing is inconsistent with matching the supply and demand for energy. 
PJM makes no effort to match the duration of supply with the duration of demand. PJM 
fails to recognize or address these issues. Data center demand is 8,760 hours per year. Since 
a four hour battery is an acceptable form of resource under the RBP, there is a significant 
 
26  
See 16 U.S.C. § 824d; TranSource, LLC v. PJM Interconnection, L.L.C., 168 FERC ¶ 61,119, 61636 
(2019) (“The courts have consistently upheld this longstanding approach to undue 
discrimination.”) citing, e.g., Complex v. FERC, 165 F.3d 992, 1012 (1999); Advanced Energy v. 
FERC, 860 F.3d 656, 670–71 (2017); Transmission Agency v. FERC, 628 F.3d 538, 549 (2010) (“A rate 
is not 'unduly' preferential or 'unreasonably' discriminatory if the utility can justify the disparate 
effect. The court will not find a Commission determination to be unduly discriminatory if the entity 
claiming discrimination is not similarly situated to others (internal quotations and citations 
omitted).”).

- 19 - 
mismatch between the supply of energy from the battery and the demand for energy from 
the data center, plus the charging demand of the battery. The same issue exists for 
standalone solar resources. The result of this mismatch will be higher energy prices for all 
PJM customers because higher cost resources will need to be dispatched to meet the 
demand for energy. 
3. The RBP Filing is inconsistent with the requirement to provide revenue 
certainty to new generation for 15 years. 
The RBP Filing is inconsistent with the requirement to provide revenue certainty to 
new generation for 15 years. The RBP Filing addresses only the capacity cost component of 
the total revenue requirement for building new capacity. The contract for differences 
addresses only the price of capacity. The RBP pricing entirely ignores net revenue from the 
energy and ancillary services markets and therefore ignores more than half the revenue for 
a new CC resource. 
4. The RBP Filing includes inconsistent definitions of the capacity that 
can satisfy the requirements to meet the data center load. 
The RBP Filing does not have a consistent definition of capacity. While the stated 
intent of the Principles and of the RBP Filing is to have 15 year capacity to meet the shortfall 
in supply resulting from data center demand, the RBP Filing allows inferior capacity to 
displace such 15 year capacity. The RBP Filing includes very different definitions of the 
capacity that can satisfy the requirements to meet the data center load. The RBP auction 
requires 15 year contracts. The RBP Filing also allows five year bilateral contracts to meet 
the same obligation under the RPB offset option. The RBP auction has a stronger definition 
of what constitutes new capacity than the RBP offset definition. The RBP Filing creates 
strong incentives to provide inferior and shorter term capacity to meet the 15 year demand. 
The RBP Filing creates strong incentives to claim capacity that is not actually new capacity 
to meet data center demand. PJM provides no reason for these weaker standards for RBP 
offset MW.

- 20 - 
The criteria for qualifying to be an RBP resource are defined in the PJM proposed 
Tariff, Attachment DD, Section 18.5(a) through (d). PJM’s proposed criteria include uprates, 
demand resources, and DER aggregation resources. The goal should be to support new 
generation and to prevent gaming of the rules by reclassifying existing capacity resources 
as new. The definition should ensure that all cleared capacity represents investment in new 
physical supply rather than redefining existing resources. PJM’s proposed criteria fail to do 
this. 
PJM’s criteria in proposed Tariff, Attachment DD, Section 18.5(b) uses the 
capitalized term Installed Capacity, but there is no proposed definition or definition in the 
existing tariff. 
The criteria for qualifying for RBP Offset UCAP MW are defined in PJM proposed 
Tariff, Attachment DD, Section 18.2. These criteria differ from the criteria to qualify for an 
RBP resource in several ways, including allowing incremental capacity created by the 
utilization of Surplus Interconnection Service; incremental CIRs or UCAP due to fuel 
switching; Planned Demand Resources and Planned DER Capacity Aggregation Resources. 
PJM fails to explain why capacity qualifying for RBP Offset UCAP MW are held to a 
weaker standard than RBP resources given that both are being used to satisfy the reliability 
shortfall. RBP offset rules also only require 5 year contracts for bilateral contracts and self 
supply versus the 15 year term for the RBP.  
The problem is that PJM proposes to treat RBP offset capacity as equivalent to RBP 
supply for purposes of reducing the regional reliability requirement, even though the two 
have materially different contractual protections and performance obligations. Under PJM’s 
RBP Filing, an offset does not need to demonstrate that it provides a substitute contribution 
to resource adequacy while reducing the RBP procurement target by that amount. The 
concern is particularly acute for DR and DER as offset MW because their UCAP 
contribution is dependent upon operating conditions, dispatch availability, customer 
participation and other factors that differ from the characteristics of conventional 
generation.

- 21 - 
There is an asymmetry. PJM is willing to reduce a 15 year regional procurement 
obligation based on offset arrangements that require only five years of contractual 
commitment. The Commission must require PJM to justify why five years of capacity is 
sufficient to offset a procurement obligation that otherwise would be satisfied through a 15 
year commitment. For DR and DER, the concern is even more pronounced because the 
commitment is to provide a specified demand reduction or DER capability, rather than to 
maintain a physical generating asset for the duration of the RBP term. 
An offset should be required to demonstrate durable capacity availability for the 
same period over which it displaces RBP procurement, or PJM needs to justify why a 
shorter commitment provides equivalent reliability value. All capacity that addresses the 
shortfall should be required to meet the same conditions. 
Table 1 summarizes the different requirements for RBP capacity and the three types 
of offset capacity.

- 22 - 
Table 1 The requirements for RBP capacity and offset capacity 
 
5. DR as capacity to meet demand of data centers 
Permitting DR and DER to serve as RBP supply creates capacity that is materially 
inferior to generation capacity resources. Committed generation is required to participate in 
PJM’s Day-Ahead Energy Market and make itself available for economic dispatch. In 
contrast, committed DR is only required to enroll in PJM’s Annual Demand Response 
program which means that its reliability benefits are only available when PJM invokes 
emergency procedures. This is analogous to permitting RBP Offset generation to classify its 
committed ICAP as maximum emergency requiring PJM to invoke emergency procedures 
in order to access its reliability benefit.  
Allowing new load to serve as its own offset through enrollment as Annual Demand 
Response further allows the new load to circumvent curtailment under IRAS. IRAS 
Gen
DR and DER
Bilateral
Self Supply
CSP or DER 
Aggregator
COD or 
under contract date
No later than June 1, 
2032
No later than June 1, 
2032
No later than June 1, 
2032
No later than June 1, 
2032
No later than June 1, 
2032
New build
New ICAP, new MFO, 
supported by new or 
transferred CIRs from a 
deactivated resource or 
a resource that 
announced deactivation 
as of April 10, 2026
NA
Not clearly defined. 
Includes transferred 
CIRs from a deactivated 
resource or a resource 
that has announced 
deactivation as of April 
10, 2026
Not clearly defined. 
Includes transferred 
CIRs from a deactivated 
resource or a resource 
that has announced 
deactivation as of April 
10, 2026
NA
Uprate
New ICAP, new MFO , 
supported by new or 
transferred CIRs
NA
New ICAP, supported 
by an increase in CIRs 
(does not specify new 
or transferred)
New ICAP, supported 
by an increase in CIRs 
(does not specify new 
or transferred)
NA
Incremental capacity 
other than uprates
Not allowable
NA
Allowable for Surplus 
Interconnection Service; 
UCAP or CIR increase 
due to fuel switching
Allowable for Surplus 
Interconnection Service; 
UCAP or CIR increase 
due to fuel switching
NA
Repowering
Deactivated, or 
announced 
deactivation, on or 
before April 10, 2026.
NA
Deactivated prior to 
April 10, 2026
Deactivated prior to 
April 10, 2026
NA
Term
15 year
15 year
At least 5 delivery years At least 5 delivery years 2028/2029 Second IA 
through 2032/2033
Load matching
Matched with load that 
has an executed electric 
service agreement or 
transmission service 
agreement, indicating 
that the load will be 
coming online in the 
2027/2028 or 2028/2029 
Delivery Year
Matched with load that 
has an executed electric 
service agreement or 
transmission service 
agreement, indicating 
that the load will be 
coming online in the 
2027/2028 or 2028/2029 
Delivery Year
2028/2029
RBP Offset UCAP MW
RBP Supply
Requirement

- 23 - 
curtailments occur prior to pre-emergency Demand Response. The new load enrolled as its 
own DR offset provides a means to subordinate its curtailment relative to curtailment 
priority under IRAS. 
PJM's proposal to permit a new data center to satisfy its own RBP obligation by 
enrolling the load as an Annual Demand Resource is flawed because it allows the load to 
receive credit against the RBP requirement without providing a reliability commitment 
equivalent to the capacity that the RBP otherwise would procure. Under the RBP Filing, a 
new load can use Annual Demand resource participation as an RBP offset through the 
2032/2033 Delivery Year whereas a committed RBP resource would be subject to a 15 year 
term. PJM therefore would permit a relatively short term demand response commitment to 
displace a capacity procurement that otherwise would provide 15 years of committed 
capacity. The reliability value of that DR also differs fundamentally from that of committed 
generation. DR is an emergency resource whose reliability contribution is realized through 
PJM’s direction to curtail load under emergency procedures, whereas a committed 
generation resource can be economically dispatched when needed, providing a continuing 
source of energy without requiring PJM to invoke emergency measures. Allowing the new 
data center to designate its own load as Annual DR further creates an opportunity to avoid 
the curtailment obligation that would otherwise apply to the load under PJM’s Interim 
Resource Adequacy Service (“IRAS”). In effect, the data center can transform a reliability 
obligation imposed on an inadequately supplied large load into a self-designated RBP 
offset, while providing PJM with a demand side resource whose availability is dependent 
on emergency curtailment rather than an economically dispatchable supply resource. This 
raises a fundamental question. PJM has not demonstrated that such DR provides reliability 
value comparable to the 15 year committed capacity that it displaces, particularly when the 
load itself is the entity receiving the benefit from the offset. PJM’s own description of the 
RBP confirms that the procurement is intended to secure a new capacity for up to 15 years 
while qualifying offsets are used to reduce the procurement target.

- 24 - 
Consider an LSE with a 1 GW data center that becomes subject to the RBP because 
its incremental load contributes to PJM’s identified resource adequacy need. Under PJM's 
proposal, the data center could enroll its entire load as an Annual Demand Resource and 
use the resulting UCAP value as an RBP offset. If the 1 GW load received 1 GW of 
qualifying DR offset credit, the data center would effectively eliminate its RBP obligation 
without PJM procuring a new generation resource to serve that capacity. Yet, the DR 
arrangement would provide a materially different commitment from the RBP capacity it 
displaces. The DR commitment would extend only through the 2032/2033 Delivery Year 
effectively, a five delivery year commitment, while an RBP resource would be committed 
for 15 years. Moreover, PJM cannot access the DR capability in the ordinary course through 
economic dispatch. The reliability benefit is available only when PJM invokes its emergency 
procedures and requires the data center to curtail. A generation resource procured through 
the RBP, by contrast, can be economically dispatched when needed and can provide energy 
without requiring PJM to declare an emergency and order the data center offline. The 
proposal therefore permits the 1 GW data center to substitute a relatively short duration, 
emergency only curtailment obligation, for the 15 year capacity commitment that otherwise 
would be procured through the RBP. It also allows the data center to avoid the curtailment 
to which it would otherwise be subject under IRAS by designating its own load as an RBP 
offset. In substance, the proposal allows the large load to satisfy the reliability obligation 
created by its own demand by making itself a demand response resource, even though that 
resource provides a fundamentally different and less durable reliability product than the 
capacity procurement it displaces. 
6. The proposed RBP process is not consistent with the cost minimizing 
principles used for clearing energy and capacity markets in PJM today. 
The proposed RBP auction clearing process is not consistent with the cost 
minimizing principles used for clearing energy and capacity markets in PJM today. The 
selection process lacks a clearly defined objective and favors resources that will offer to 
provide capacity with a commercial operation date in 2028/2029 over resources that need

- 25 - 
additional time to achieve commercial operation even when the later resources are less 
costly and have better reliability characteristics.27 The RBP’s use of a pay as bid approach 
coupled with the failure to include market power mitigation will result in the exercise of 
market power. The RBP Filing includes a levelized cost calculation that PJM has not 
supported or explained. PJM’s defines the Levelized Cost ($ per MW-day) as the Present 
Value of future revenues (Offer Price*UCAP Offered) divided by the sum of discounted 
offered UCAP MW values.28 PJM proposed to use a discount rate equal to 9.5 percent after 
tax average weighted average cost of capital for discounting the revenues and UCAP MW. 
Discounted cash payments are well understood and frequently used for comparing 
revenues or investment opportunities spread over future years, but it is not clear what 
discounted UCAP MW mean. For example, $100 in five years is worth $63.52 today. 
Applying PJM’s logic and discount rate, 100 MW of UCAP in five years has a discounted 
value of 63.52 MW. PJM does not explain the meaning of a discounted MW.  
A better approach for comparing offers with varying UCAP MW would be to divide 
the levelized annual revenue from the RBP payments by the average UCAP MW. The 
levelized annual revenue is equal to the present value of the RBP payments multiplied by a 
capital recovery factor (CRF). 29 The average UCAP MW represents the expected UCAP MW 
over a time period unlike the discounted UCAP MW which understates the expected UCAP 
 
27  
Attachment A - Revisions to the PJM Open Access Transmission Tariff and PJM Reliability 
Assurance Agreement at 18.5 The Reliability Backstop Procurement Process (“Attachment A – 
Marked Tariff Records”).) 
28  
Under the PJM ‘s proposed approach, sellers of RBP capacity provide PJM offer price in $/MW-day 
and offer MW for every delivery year between the expected commercial operation date and the 
maximum term of 15 years that does not extend beyond the 2042/2043 Delivery Year. 
29  
A CRF is used to convert a present day dollar amount into an equivalent level payment over a 
period of years. PJM currently uses CRF factors to determine capital recovery payments for black 
start generators and incremental investments in the definition of avoidable cost for capacity 
resources.

- 26 - 
MW. This approach also does not give preference to resources that need less time to achieve 
commercial operation. 
The proposed RBP procurement selection process lacks a clearly defined objective. In 
the PJM annual capacity market, the objective is to minimize the total procurement cost to 
meet the reliability requirement. The objective is met after evaluating all feasible tradeoffs. 
This is accomplished through a linear optimization algorithm. The RBP procurement 
approach first ranks the offers based only on expected commercial operation date. A sell 
offer with an earlier commercial operation date is preferred over a project with lower cost 
and better reliability characteristics, but a later commercial operation date. For example, the 
proposed RBP clearing logic would choose a demand response alternative with an earlier 
commercial operation date and a higher price over a combined cycle with a later 
commercial operation date and a lower price. The RBP iterative selection approach does not 
include the fundamental cost minimization principles that are essential to a competitive 
market and are the basis for capacity procurement in the annual PJM Capacity Market. 
After ordering all received offers based on the expected commercial operation date, PJM 
iteratively selects and unselects the sell offers to select a first combination of sell offers that 
exceeds the shortfall such that the combined levelized cost falls below the maximum 
willingness to pay. PJM does not exhaustively examine any more offers in the ordered list 
to explore the potential for finding a cheaper combination. Even under PJM’s purported 
levelized cost metric, the combination chosen by PJM will not necessarily be the least cost 
solution. 
PJM fails to provide any meaningful support for this ineffective and inefficient 
approach. 
PJM’s levelized cost calculation does not correctly reflect the cost to provide capacity 
and will distort the selection process. Through discounting the future MW in the levelized 
cost calculation and through ordering the resource for selection based on the earlier 
commercial operation date, PJM would give preference to expensive offers with lower

- 27 - 
UCAP MW in the earlier years over cheaper offers with higher UCAP MW in the later 
years. 
7. PJM failed to update the maximum price calculation 
PJM failed to update the calculation of energy market net revenues that is used to 
offset Gross CONE to calculate the Net CONE value used as the maximum price in the RBP 
of $555/MW-day. Based on the forward looking method used to calculate the $555/MW-day 
number, net revenues are significantly higher than the net revenues used by PJM. As a 
result, PJM has significantly overstated the maximum price for the RBP. 
PJM failed to explicitly address energy market net revenues in the RBP Filing. 
However, the price cap of $555/MW-Day UCAP used by PJM in the RBP Filing was based 
on a very specific value of energy market net revenues.  
Net CONE is equal to Gross CONE less energy and ancillary net revenues (EAS). If 
EAS increases, Net CONE decreases. At the August 22, 2025, Market Implementation 
Committee, PJM presented Net CONE values for each CONE area as well as the RTO, and 
specified that the dates of the forwards were the 30 trade dates that conclude in August 
2025.30 The CONE Area and RTO Net CONE values are the same as the Net CONE values 
shown by zone in the Marzewski Affidavit in Table 3.31 
The $555/MW-Day price cap of the RBP is the RTO Net CONE based on those 
August 2025 forward prices. The August 2025 forwards are now a year out of date. Forward 
prices have substantially increased since August 2025. Comparing forward prices for the 
 
30  
Skyler Marzewski, CONE Operating Parameters for Net EAS, and Net CONE Updates. Market 
Implementation Committee. (August 22, 202). The date of these forwards is: 30 trade dates that 
concluded in August 2025.  
31  
2025 Periodic Review of Variable Resource Requirement Curve Shape and Key Parameters, 
Affidavit of Skyler Marzewski in Docket No. ER26-455-000, (“Quad Review Filing”). (November 7, 
2025) (“Marzewski Affidavit”).

- 28 - 
2028/2029 Delivery Year as of August 1, 2025, to August 1, 2026, average hourly Western 
Hub LMPs have increased by $14/MWh, or 24 percent.  
If forwards are 24 percent higher, EAS is higher, and point A of the VRR Curve = 
max[(1.15 x Gross CONE - 0.75 x Net E&AS) or (0.2 x Gross CONE)] is $473/MW-Day 
UCAP, not $555/MW-Day UCAP.32 
PJM should be required to use an accurate maximum price, based on PJM’s 
approved method. 
C. Rejecting the RBP Filing Would Allow the Commission to Direct and 
Appropriate Remedy. 
1. The Current Rules Are Inadequate to Address Prevailing Market 
Conditions. 
The Market Monitor has extensively documented the fact that the application of the 
current tariff is unjust and unreasonable and produces results that are not competitive.33 34 
2. The Record Provides Sufficient Information for the Commission to 
Immediately Issue a Remedial Directive that Protects Reliability and 
Affordability. 
Upon issuing a finding that the current rules are unjust and unreasonable, the 
Commission can, on the basis of the existing record, direct PJM to implement a remedy 
(“Remedial Directive”). The Remedial Directive is based on the Market Monitor Proposal 
(Attachment A), but streamlined to allow for immediate issuance of a directive that 
includes the core concepts while deferring full consideration and approval of the details. 
 
32  
See Technical Appendix, included as Attachment B to this filing, for more details on the calculation. 
33  
See Monitoring Analytics, LLC “Analysis of the 2027/2028 RPM Base Residual Auction – Part A,” 
(January 5, 2026). 
34  
See Monitoring Analytics, LLC, 2026 Quarterly State of the Market Report for PJM: January through June 
(August 13, 2026) Section 1: Introduction.

- 29 - 
The Remedial Directive should direct that PJM file, within two weeks, rules and 
procedures with the following elements: 
• 
PJM should, working with LSEs and EDCs, immediately identify data center 
load not interconnected by June 1, 2026, and remove it from RPM capacity 
market auctions. 
• 
PJM should establish criteria to be included in the RAA defining the obligations 
of LSEs to require that new data center loads have 15 year bilateral contracts with 
new generation that do not permit any cost or risk shifting to other customers. 
The contracts would be based on general terms and conditions in accordance 
with tariff defined criteria with the cost and risk specifics defined by the data 
centers and generators.  
• 
For LSEs with data centers unable to make independent arrangements meeting 
the criteria, PJM should run a full single clearing price auction using the BRA 
capacity market clearing model for new data center load. LSEs would require 
data centers to participate in the reliability backstop auction if they do not have a 
bilateral contract for new generation that meets the requirements of such 
contracts. When the clearing process is complete, the LSEs would require that 
generators and data center loads enter into 15 year bilateral contracts that do not 
permit any cost or risk shifting to other customers. The contracts would be based 
on general terms and conditions in accordance with tariff defined criteria with 
the cost and risk specifics defined by the data centers and generators. 
• 
PJM should establish curtailment obligations for wholesale service to data 
centers during a defined transition period that would allow all data centers the 
time to contract for new generation. 
These requirements can be implemented immediately and can be relied upon to 
meet the goals of the Pledge and Principles.

- 30 - 
The Commission has exclusive jurisdiction over the terms and conditions of 
wholesale power sales and the bulk power grid.35 The capacity obligation of LSEs to 
support resource adequacy is a term and condition of wholesale power sales subject to the 
Commission’s exclusive jurisdiction.36 37 The Remedial Directive applies to LSEs and the 
terms and conditions necessary to meet capacity obligations to PJM, and these terms cannot 
be changed by States.38 The Supreme Court has determined that Federal regulation in this 
field preempts state regulation. 39 The Remedial Directive does not regulate retail power 
sales. The Commission’s jurisdiction to determine whether LSEs have met capacity 
obligations related to resource adequacy does not intrude on the jurisdiction over 
generation reserved to the States.40 The Commission initiated a proceeding to address 
 
35  
See 16 U.S.C. § 824. 
36  
See Hughes v. Talen Energy Mktg., LLC, 578 U.S. 150, 163 (2016) (“We agree with the Fourth 
Circuit’s judgment that Maryland’s program sets an interstate wholesale rate, contravening the 
FPA’s division of authority between state and federal regulators. As earlier recounted, … the FPA 
allocates to FERC exclusive jurisdiction over “rates and charges . . . received . . . for or in connection 
with” interstate wholesale sales. §824d(a). Exercising this authority, FERC has approved the PJM 
capacity auction as the sole rate setting mechanism for sales of capacity to PJM, and has deemed 
the clearing price per se just and reasonable”). 
37  
RAA Article 7. 
38  
See Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 972 (1986) (“[I]n formulating rates 
over which it has exclusive jurisdiction, FERC ruled that the NFA and AA should be treated as 
allocating 22.5% of the entitlement power of the Tapoco-Nantahala system to Nantahala's 
customers and 77.5% of that power to Tapoco's customer. That allocation, reflected as it is in a filed 
rate, must be respected by NCUC. If, as a result, Nantahala needs to purchase additional power 
from some nonentitlement source, that need is a reasonable one.’). 
39  
See id (state action targeting rates for capacity preempted by federal occupation of the field), citing 
EPSA, 577 U.S. 260, 288 (2016) (“The FPA leaves no room either for direct state regulation of the 
prices of interstate wholesales or for regulation that would indirectly achieve the same result.” 
(internal quotation marks omitted”). 
40  
See id. at 164 (“That Maryland was attempting to encourage construction of new in-state generation 
does not save its program. States, of course, may regulate within the domain Congress assigned to 
them even when their laws incidentally affect areas within FERC’s domain. See Oneok, Inc. v. 
Learjet, Inc., 575 U. S. 373, 385, 135 S. Ct. 1591, 191 L. Ed. 2d 511, 528 (2015) (whether the Natural

- 31 - 
matching costs of new transmission network upgrades to data centers.41 A similar and 
complementary proceeding is needed to match of the costs of new resources to support 
resource adequacy to data centers.  
 The Remedial Directive provides terms and conditions for wholesale energy service 
to support resource adequacy, similar, in so far as the Commission’s jurisdiction is 
concerned, to the Fixed Resource Requirement (“FRR”) alternative that allows for eligible 
LSEs to satisfy PJM’s capacity requirements through a plan consisting of a list of owned or 
controlled resources meeting PJM’s criteria.42 Under the RAA’s provisions for FRR 
alternative plans, an LSE takes the responsibility and risk to procure, by contract or 
ownership, resources needed to support resource adequacy in the PJM region. PJM’s role is 
limited to ensuring that resources meet the applicable criteria. Under the Remedial 
Directive, LSEs serving data centers are required to identify data center load, so that PJM 
can remove it from RPM Auctions, and reviews LSEs’ resources included in its plan to meet 
capacity obligations related to data centers. The Remedial Directive builds upon the 
voluntary matching process element of the RBF Proposal (at 30–31), which allows LSEs to 
satisfy their capacity obligations through resources, procured by contract or ownership, that 
meet PJM criteria. There is no material difference, in so far as the Commission’s exclusive 
jurisdiction over resource adequacy is concerned,43 between the Remedial Directive and the 
existing FRR alternative rules, and the voluntary matching element of the RBP Filing. PJM’s 
administration of the RAA and FRR plans approved by FERC since 2006 has never been 
 
 
Gas Act (NGA) preempts a particular state law turns on “the target at which the state law 
aims”).[citation omitted] But States may not seek to achieve ends, however legitimate, through 
regulatory means that intrude on FERC’s authority over interstate wholesale rates, as Maryland has 
done here.”); see also Conn. Dep't of Pub. Util. Control v. FERC, 569 F.3d 477, 481 (2009). 
41  
See Large Loads Show Cause Order. 
42  
See RAA Schedule 8.1. 
43  
See Hughes, 578 U.S. 150.

- 32 - 
found outside of FERC’s jurisdiction nor has the issue of jurisdictional basis for the RAA 
and FRR plans been raised on appeal.44 
The reason why the RBP Filing should be rejected, and the Remedial Directive 
should issue instead, is the broadly recognized need to protect reliability and affordability 
in the PJM Region. The RBF Filing fails to address reliability and may lock in 
unaffordability in the PJM Region for 15 years. Meanwhile, contrary to the fundamental 
goals of the Pledge and Principles, PJM has shifted the costs and risks of the data center 
developers who are driving the extraordinary and immediate need for new resources to 
existing customers even though the data centers are ready and willing to assume the costs 
and risks they create. The Remedial Directive can fully and timely implement the goals of 
the Pledge and Principles.  
II. CONCLUSION 
The Market Monitor respectfully requests that the Commission afford due 
consideration to this pleading as the Commission resolves the issues raised in this 
proceeding. 
 
Joseph E. Bowring 
Independent Market Monitor for PJM 
President 
Monitoring Analytics, LLC 
2621 Van Buren Avenue, Suite 160 
Eagleville, Pennsylvania 19403 
(610) 271‐8051 
joseph.bowring@monitoringanalytics.com 
 
Respectfully submitted, 
 
Jeffrey W. Mayes 
 
General Counsel 
Monitoring Analytics, LLC 
2621 Van Buren Avenue, Suite 160 
Eagleville, Pennsylvania 19403 
(610) 271‐8053 
jeffrey.mayes@monitoringanalytics.com 
 
44  
See PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006), order on reh’g, 119 FERC ¶ 61,318 (2007).

- 33 - 
Catherine A. Tyler 
Deputy Market Monitor 
Monitoring Analytics, LLC 
2621 Van Buren Avenue, Suite 160 
Eagleville, Pennsylvania 19403 
(610) 271‐8050 
catherine.tyler@monitoringanalytics.com 
Paul G. Scheidecker 
Senior Analyst 
Monitoring Analytics, LLC 
2621 Van Buren Avenue, Suite 160 
Eagleville, Pennsylvania 19403 
(610) 271‐8050 
paul.scheidecker@monitoringanalytics.com 
Alexandra Salaneck 
Senior Analyst 
Monitoring Analytics, LLC 
2621 Van Buren Avenue, Suite 160 
Eagleville, Pennsylvania 19403 
(610) 271‐8050 
alexandra.salaneck@monitoringanalytics.com 
John Hyatt 
Senior Economist 
Monitoring Analytics, LLC 
2621 Van Buren Avenue, Suite 160 
Eagleville, Pennsylvania 19403 
(610) 271‐8050 
john.hyatt@monitoringanalytics.com 
Devendra R. Canchi 
Senior Analyst 
Monitoring Analytics, LLC 
2621 Van Buren Avenue, Suite 160 
Eagleville, Pennsylvania 19403 
(610) 271‐8050 
devendra.canchi@monitoringanalytics.com 
 
Dated: August 21, 2026

ATTACHMENT A 
Market Monitor Proposal

© Monitoring Analytics 2026 | www.monitoringanalytics.com 
DATE: 
June 30, 2026, Meeting Date 
TO: 
CIFP: Reliability Backstop  
FROM: 
IMM 
SUBJECT: 
Proposed reliability backstop auction design V6 
The most important criterion for evaluating proposals to address how to reliably serve new 
data center load is the assignment of the costs and risks associated with LSEs serving data 
center load.1 For example, the failure to exclude new data center load from the BRAs, as PJM 
proposes, would by definition impose significant costs on other customers and therefore violate 
the basic principle that data center costs should not be imposed on other customers. The rules 
must protect just and reasonable pricing for capacity that serves existing customers. To date, 
the capacity costs imposed on existing customers by data centers have been $23 billion.2 As 
another example, PJM’s proposal assigns the ultimate backstop risk associated with serving 
data center load to other PJM customers, whether it derives from an expected data center not 
showing up or the matching new generation not showing up. In contrast, the IMM’s proposal 
stipulates that LSEs require the data centers to enter into 15 year bilateral contracts with new 
generation resources that assign costs and risks between the two parties to the bilateral contract. 
The IMM proposal adds obligations to the RAA that require LSEs serving data center loads to 
demonstrate that the data centers have entered into bilateral contracts for new capacity that 
meet defined criteria. This is analogous to the requirements for FRR entities. 
The preferred option for LSEs serving data centers that add load to the PJM system is for LSEs 
to require, as a term and condition of service for such data centers, that the data centers bring 
their own new generation (BYONG).3 For those LSEs serving data centers that do not bring 
their own new generation that meets the defined requirements, the IMM proposes that PJM 
run a reliability backstop auction (RBA) designed to meet all LSEs’ expected data center load 
that has not entered into a 15 year bilateral contract with new generation. 
The IMM proposes a specific reliability backstop auction design.  The goal is to incorporate 
market forces as much as possible and to minimize planning choices by PJM or others. The 
 
1  
The Supreme Court has recognized FERC’s jurisdiction to ensure resource adequacy through the 
RAA and auctions conducted under the RAA, and, further, that these federal rules preempt state 
actions interfering with that regulatory construct. See Hughes v. Talen Energy Mktg., LLC, 578 U.S. 
150, 155 (2016) (recognizing FERC’s and RTO’s authority, including through capacity market 
auctions, to “ensure the availability of an adequate supply of power at some point in the future.”). 
2  
See the “Analysis of the 2027/2028 RPM Base Residual Auction – Part A,” (January 5, 2026) 
<https://www.monitoringanalytics.com/reports/Reports/2026/IMM_Analysis_of_the_20272028_RP
M_Base_Residual_Auction_Part_A_20260105.pdf>. 
3  
The MW of new generation to meet data center load is in UCAP terms and includes reserves based 
on the system target reserve margin.

© Monitoring Analytics 2026 | www.monitoringanalytics.com 
2 
proposed IMM design does not impose data center costs or risks on LSEs or EDCs or PJM or 
other customers, consistent with the Principles defined by the National Energy Dominance 
Council and the PJM Governors and the Pledge by defined hyperscalers.4 
The IMM design creates a dedicated mechanism for LSEs serving new large data center load 
designed to complement, not replace, PJM’s existing RPM construct. It is intended to ensure 
long term resource adequacy for data center load by directly linking LSEs’ service to new data 
center load with dedicated new generation, creating transparent investment signals based on a 
15 year contract term. 
Only organic load and existing data center load as of June 1, 2026, would be included in the 
2028/2029 BRA and in the 2029/2030 BRA. The maximum price for these BRAs would be based 
on the IMM’s CT net CONE calculations from the most recent quadrennial review, updated to 
reflect current market conditions as necessary.5 There would be no floor price. All forecast data 
center load would be removed from the 2028/2029 BRA and from the 2029/2030 BRA. All LSEs 
serving data center load that was not online on June 1, 2026, would be required to commit to 
requiring that data center loads have contracts that meet the requirements of the BYONG 
option, or to participating in the reliability backstop auction. LSEs serving data center load 
would have the option to commit to requiring a specific future BYONG plan that meets the 
necessary terms and conditions and not be included in the auction. If a data center load does 
not meet the requirement to bring new generation, the data center load would be subject to the 
curtailment alternative. If data center load takes the BYONG option, the IMM’s proposal is that 
the bilateral BYONG contracts be required to have the same basic characteristics as the bilateral 
contracts resulting from the reliability backstop auction, e.g. a 15 year term, must offer 
obligation in the capacity market at zero price, must offer obligation in the energy market at 
cost-based offers, location in the same child LDA, and matching energy output duration with 
load duration on an hourly basis. All capacity resources would be treated as capacity resources 
under the PJM Tariff rules. 
The IMM’s design for the reliability backstop auction is to run a full single clearing price auction 
using the BRA capacity market clearing model for data center load. LSEs would require data 
centers to participate in the reliability backstop auction if they do not have a bilateral contract 
 
4  
See National Energy Dominance Council, Statement of Principles Regarding PJM (January 16, 2026) 
<https://www.energy.gov/documents/statement-principles-regarding-pjm>; see also White House, 
“Ratepayer 
Protection 
Pledge 
Proclamation,” 
(March 
4, 
2026) 
<https://www.whitehouse.gov/presidential-actions/2026/03/ratepayer-protection-pledge-
proclamation/>. 
5  
See PJM. Markets and Reliability Committee, Quadrennial Review Issues < https://www.pjm.com/-
/media/DotCom/committees-groups/committees/mrc/2025/20250925/20250925-item-05b---
quadrennial-review-imm-proposal---presentation.pdf> (September 25, 2025).

© Monitoring Analytics 2026 | www.monitoringanalytics.com 
3 
for new generation that meets the requirements of such contracts. This reliability backstop 
auction would be run soon after the 2028/2029 BRA. Such an auction design could be repeated 
in the future as needed to address additional new data center load that is not included in the 
first reliability backstop auction but would not be required and would not be run on a 
predefined schedule. The reliability backstop auction would include the location and MW of 
each data center that participates, the location and MW of proposed generation that 
participates, full PJM CETO/CETL parameters net of the impacts from the applicable BRA, and 
any resultant locational price separation. The only product offered would be 15 year generation 
capacity at a maximum offer price equal to the nominal levelized equivalent of the IMM’s 
calculated combustion turbine Gross CONE provided in the latest quadrennial review, 
updated to reflect current market conditions as necessary, net of defined energy and ancillary 
service net revenues in each year of the contract. That equivalent, in $/MW-day, would be 
higher than the calculated net CONE in year one because the product is based on a 15 year 
levelized gross CONE while the current cap is based on a 20 year levelized gross CONE net of 
net revenues for year one.  
The reliability backstop auction would result in cleared generation capacity by LDA. If offers 
are less than demand, the demand offers would clear in order from highest to lowest. If demand 
is less than offers, the supply offers would clear in order from lowest to highest. After the 
auction, a matching algorithm would be used to match individual cleared generation resources 
with individual data centers subject to locational constraints such that the number of bilateral 
contracts are minimized.   
In order to meet the intended incentive goal, the total payments received for new generation 
should equal Gross CONE, including both net revenue from the energy and ancillary services 
markets and capacity payments. The net revenues would be explicitly incorporated. The actual 
annual payments under the contracts would include the defined energy and ancillary service 
net revenues calculated annually for each year and the remaining net CONE not covered by 
the net revenues. The contracts would be for total payments including energy and ancillary 
services net revenues and the remaining net cost of capacity. The energy and ancillary services 
revenues could be calculated annually on a forward looking basis or on an historical basis. A 
single method should be selected that applies to all contracts. 
In the reliability backstop auction, the demand for generation capacity would be equal to the 
specific demand for 15 year capacity from individual data centers, plus the required reserve 
margin, for each data center, to ensure reliability. There is no forecast of demand, by EDCs or 
by PJM. All data centers with expected demand greater than or equal to 5.0 MW would be 
included in the auction. A goal of the defined size is to prevent artificial segmentation of data 
center load to circumvent the size threshold. The maximum price for the demand bids would 
equal the maximum offer price for new generation.

© Monitoring Analytics 2026 | www.monitoringanalytics.com 
4 
Sellers in the reliability backstop auction would be new generation only, with clearly defined 
eligibility. New generation would not include uprates to existing generation, uncleared 
capacity, repowered capacity, units that retired after June 1, 2025, demand side resources or 
relicensing. This definition ensures that all cleared capacity represents investment in new 
physical supply rather than redefining existing resources. The goal is to support new 
generation and to prevent gaming of the rules by reclassifying existing capacity resources as 
new. The new generation must be located within the same child LDA as the data center to help 
ensure long term deliverability to that load over the 15 year life of the contract. The output of 
the new generation must reasonably match the hour by hour load profile of the data center. 
(This is not capacity factor matching.) For example, a standalone solar resource would not 
qualify but a combined solar and battery resource could qualify. The energy output of the new 
generation must equal or exceed the data center load whenever the new generation is available, 
subject to locational constraints. 
Generation selected in the reliability backstop auction would be required to comply with all 
requirements of the PJM capacity market. For example, new generation capacity is required to 
have CIRs and to be deliverable and has an RPM must offer obligation. All of this generation 
would also be required to have the same obligations in the energy market as committed 
generation capacity resources, including an energy market must offer obligation. 
When the clearing process is complete and each generation offer is associated with one or more 
identified data center loads, the LSEs would require that generators and data center loads enter 
into 15 year bilateral contracts that do not permit any cost or risk shifting to other customers. 
The contracts would be based on a tariff defined standard contract. The risks associated with 
the load changing or withdrawing and generation changing or failing would be fully addressed 
in the bilateral contracts. New generation capacity resources clearing in the reliability backstop 
auction would have an initial capacity accreditation based on the recent EFORd performance 
of comparable generation and would, after two years of operation, have unit specific ELCC 
values based on actual unit performance and therefore subject to management by the generator. 
The risks associated with changes in capacity accreditation values would be fully addressed in 
the bilateral contracts. 
When the bilateral contracts are final, including bilateral contracts reached under the BYONG 
option, the data center load plus the reserve margin has an RPM must buy obligation and the 
corresponding generation capacity has an RPM must offer obligation, after the capacity 
commercial operation date, in future BRAs as price takers for the 15 year contract term. A 
contract for differences would ensure that the load pays and the generation receives the 
contract price in the financial settlement. 
The IMM’s proposal addresses any potential state/federal jurisdictional issues. LSEs would be 
required, as a condition of service, in the RAA, to show that each data center that they serve 
has a bilateral contract(s) in place with a source of generation for at least 15 years that meets

© Monitoring Analytics 2026 | www.monitoringanalytics.com 
5 
the identified requirements of such contracts. The bilateral contracts would address all pricing 
and risk issues solely between the parties to the contract with no recourse to other customers. 
Under the IMM proposal, the qualifying bilateral contracts assign all risks to the bilateral 
counterparties and no risks are assignable to EDCs, LSEs, PJM or any other customers. The 
LSEs must ensure that the data centers meet the requirement to have a bilateral contract based 
on the requirements of the RAA, but the LSEs are not counterparties to the capacity supply 
contract. LSEs that do not maintain their obligations under the RAA will face consequences 
defined in the RAA.6  The data center and the generation capacity seller are the counterparties 
to the capacity supply contracts. PJM and other PJM participants provide no credit support of 
any kind for the contracts. There is no recourse to PJM or its members. Credit issues are entirely 
between the parties to the bilateral contracts. 
 
 
6  
See RAA § 5.2, referencing OA § 15.1. The RAA can be amended only by action of the PJM Board 
and FERC approval, per RAA § 16.4.

- 0 - 
 
 
 
 
 
ATTACHMENT B 
Technical Appendix

- 1 - 
A. Issues with PJM’s maximum price 
Table 2 shows PJM CT Gross and Net CONE, including the PJM Net CONE value 
based on August 2025 forwards and an estimated Net CONE value based on August 2026 
forwards 
Table 2 PJM CT Gross and Net CONE 
 
 
 
 
PJM CT Gross & Net CONE ($/MW-Day)
EMAAC
SWMAA
C Rest of RTO
WMAAC
COMED
RTO
Gross CONE (ICAP)
$596
$608
$590
$592
$679
$613
Forward E&AS (67th percentile)
$159
$343
$394
$320
$214
$361
Net CONE (ICAP)
$438
$265
$195
$271
$465
$228
Gross CONE (UCAP)
$754
$769
$747
$749
$860
$776
Net CONE (UCAP)
$554
$336
$247
$343
$589
$325
VRR Curve (UCAP)
a1) 1.15 x Gross CONE - 0.75 x Net E&AS
$718
$560
$483
$557
$785
$555
a2) 0.2 x Gross CONE
$151
$154
$149
$150
$172
$155
Point A (99% of RR, max of a1,a2)
$718
$560
$483
$557
$785
$555
Point B (101.5% of RR, 0.5 x Point A)
$359
$280
$242
$278
$393
$278
Point C (106.0% of RR, $0)
$0
$0
$0
$0
$0
$0
a1) 1.15 x Gross CONE - 0.75 x Net E&AS (EAS 24% higher)
$473

- 2 - 
 
CERTIFICATE OF SERVICE 
I hereby certify that I have this day served the foregoing document upon each 
person designated on the official service list compiled by the Secretary in this proceeding. 
Dated at Eagleville, Pennsylvania, 
this 21st day of August, 2026. 
 
Jeffrey W. Mayes 
General Counsel 
Monitoring Analytics, LLC 
2621 Van Buren Avenue, Suite 160 
Eagleville, Pennsylvania 19403 
(610)271‐8053 
jeffrey.mayes@monitoringanalytics.com