{"document":{"slug":"filing-20260821-5317","title":"Protest of the Independent Market Monitor for PJM re PJM Interconnection, LLC's 07/31/2026 proposed Reliability Backstop Procurement filing","issued":"2026-08-21","accession":"20260821-5317","docket":"ER26-3380-000","group":"PJM filings","filer":"Monitoring Analytics, LLC","kind":"filing","file":"sources/originals/20260821-5317_01.pdf","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_Number=20260821-5317","sha256":"5691314f7dd1816b1e2fdcb12313e961644b93176ce8f6eb3789fbab7b62c9b7","pages":42,"tokens":13452,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":240,"text":"UNITED STATES OF AMERICA \nBEFORE THE \nFEDERAL ENERGY REGULATORY COMMISSION \n \nPJM Interconnection, L.L.C. \n) \n) \n) \n \n \nDocket No. ER26-3380-000 \nPROTEST OF THE INDEPENDENT MARKET MONITOR FOR PJM \nPursuant to Rule 211 of the Commission’s Rules and Regulations1 Monitoring \nAnalytics, LLC, acting in its capacity as the Independent Market Monitor (“Market \nMonitor”) for PJM Interconnection, L.L.C. (“PJM”),2 submits this protest to the filing \nsubmitted by PJM Interconnection, L.L.C. (“PJM”) on July 31, 2026, proposing (at 1) “to \nestablish the Reliability Backstop Procurement (“RBP”)—a one-time procurement of new \ncapacity to address resource adequacy challenges in the PJM Region arising from \ninsufficient commitments of capacity in the 2027/2028 and 2028/2029 Reliability Pricing \nModel (“RPM”) Auctions, primarily driven by the unprecedented addition of large loads, \nmost notably data centers” (“RBP Filing”).3 \nThe RBP Filing has not been supported as just and reasonable, and it should be \nrejected. The RBP Filing is unjust and unreasonable, and attempting to implement it will \n \n1 \n18 CFR § 385.211 (2026). \n2 \nCapitalized terms used herein and not otherwise defined have the meaning used in the PJM Open \nAccess Transmission Tariff (“OATT”), the PJM Operating Agreement (“OA”) or the PJM Reliability \nAssurance Agreement (“RAA”). \n3 \nThe RBP Filing is supported by an (i) Affidavit of Ms. Danielle Croop on Behalf of PJM (Attachment \nC) (“Croop Affidavit”) and an (ii) Affidavit of Gwen Kelly on Behalf of PJM (Attachment D) (“Kelly \nAffidavit”)."},{"page":2,"startToken":240,"endToken":710,"text":"- 2 - \nseverely damage PJM markets, create unintended consequences, and compound that \ndamage for a period of 15 years. \nThe problem that the RBP Filing is designed to address is real and needs immediate \naction. The current rules are not designed to address the extraordinary circumstances that \nconfront the PJM markets today. PJM has done nothing to prevent the interconnection of \ndata centers that it does not have the capacity to serve. Timely action is needed to protect \nresource adequacy in the PJM Region while ensuring that data centers pay for the capacity \nthey need and bear the risks they impose. There is broad agreement among policy makers, \nregulators, and developers, captured in the Ratepayer Protection Pledge and Principles, on \nthe need to ensure that data centers bring their own new generation and pay their own way \nand to prioritize the protection of reliability and affordability for all the other customers.4 5 \n \n4 \nSee \nThe \nWhite \nHouse, \n“Ratepayer \nProtection \nPledge” \n(March \n4, \n2026), \n, Proclamation No. 11014, 91 Fed. Reg. 11439 (Mar. 4, \n2026) (“Today, pursuant to the Ratepayer Protection Pledge, leading United States hyperscalers \nand AI companies guarantee that data centers’ energy needs will not increase household electricity \ncosts for American citizens. Instead, these companies will build, bring, or buy the new generation \nresources and electricity needed to satisfy their energy demands, and pay for all new power \ndelivery infrastructure upgrades to service their data centers. They will voluntarily negotiate new, \nseparate rate structures with their utilities and relevant State governments, and pay those rates, and \nfor their infrastructure, whether they use the electricity or not. They will also invest in local \ncommunities and coordinate with grid operators to contribute to a more reliable grid.”) (“Pledge”). \nOn July 23, 2026, over 200 additional entities joined the pledge. See The White House, “President \nTrump’s Ratepayer Protection Pledge Secures American AI Dominance, Protects Consumers” (July \n23, \n2026), \n. \n5 \nNational Energy Dominance Council, Statement of Principles Regarding PJM (January 16, 2026) \n (“Principles”). Two principles \napply to the contemplated procurement of new generation. First, the procurement should \n“[p]rovide 15-year price certainty for new capacity resources” [emphasis]. The statement notes that \nthis can be done in through a “Reliability Backstop Auction,” but does not require that this auction \nbe a centralized procurement by PJM or that PJM customers assume risks. Second, “PJM should \nallocate the cost of any new capacity through the aforementioned Reliability Backstop Auction to \nload serving entities (LSEs) with new data centers that have not self-procured new capacity or \nagreed to be curtailable.” The principles, agreed to by the Governors of PJM States Indiana, Ohio,"},{"page":3,"startToken":710,"endToken":1206,"text":"- 3 - \nThe Pledge affirms: “The Ratepayer Protection Pledge and the commitments embodied \ntherein effectuate the national policy of the United States.” The Commission has recognized \nthe Pledge and Principles.6 The Pledge and Principles should guide the development of \nrules to support resource adequacy by procuring new capacity to serve data centers and \nensuring that data centers pay for that capacity and that those costs are not assigned, \nallocated or otherwise pushed onto other customers. \nAccordingly, in addition to rejecting the RBP Filing as not shown to be just and \nreasonable, an order should issue, finding that the existing rules relating to resource \nadequacy for serving data centers in the PJM Region are unjust and unreasonable under \nSection 206 of the Federal Power Act.7 Upon issuing a finding that the current rules are \n \n \nMaryland Pennsylvania, Virginia, West Virginia, Delaware, Illinois, Michigan, New Jersey, \nTennessee, North Carolina and Kentucky, call for PJM to do the allocation and to match data \ncenters to the costs not excluding risks of new resources or commitments to curtail. Additional \nprinciples that going beyond the RBF Proposal, the Market Proposal, or potential alternatives, \ninclude: (i) extending the price collar for two additional RPM Base Residual Auctions, (ii) PJM \nimproving load forecasting, (iii) accelerating generator interconnections, i.e., the Reliability \nResource Initiative (RRI), and (iv) continued efforts to reform the capacity market. \n6 \nSee PJM Interconnection, L.L.C., 195 FERC ¶ 61,211 at PP 2, 5, 8, 32 & 69 (2026) (“Large Load Show \nCause Order”). The Large Loads Show Cause Order states (at P 66) (“We next preliminarily find \nthat PJM’s Tariff appears to be unjust and unreasonable because it lacks adequate mechanisms to \nmitigate the risk of cost shifting among transmission customers, which may result in unjust and \nunreasonable rates for transmission service. In particular, we are concerned about the apparent lack \nof: (1) transparency regarding the assignment of Network Upgrades, and their associated costs, that \nare needed to provide transmission service to Eligible Customers on behalf of large loads; and (2) a \npro forma cost recovery agreement between PJM, the relevant transmission owner, and the Eligible \nCustomer taking transmission service on behalf of large loads that help ensure that Eligible \nCustomers bear the risk and are ultimately responsible for costs incurred to provide transmission \nservice, including the cost of Network Upgrades.”). \n7 \nSee 16 U.S.C. § 824e(a); see also Large Loads Show Cause Order at P 49 (“[W]e today exercise our \nauthority to ensure that the process by which jurisdictional transmission providers and/or \ntransmission owners will study the provision of jurisdictional transmission service to Eligible \nCustomers on behalf of large loads interconnecting to the transmission system, including where, as \nallowed by state law or a public utility’s voluntary offer of such service, an end-use large load seeks \nunbundled retail transmission service, is just and reasonable and not unduly discriminatory or \npreferential. Pursuant to that authority, we find that PJM’s Tariff appears to be unjust and"},{"page":4,"startToken":1206,"endToken":1505,"text":"- 4 - \nunjust and unreasonable, the Commission can, on the basis of the existing record, act \nwithout delay to direct PJM to immediately implement a remedy. \nA remedial order should direct that PJM file, withing two weeks, a solution with the \nfollowing elements: \n• \nPJM should, working with LSEs and EDCs, immediately identify data center \nload not interconnected by June 1, 2026, and remove it from RPM capacity \nmarket auctions. \n• \nPJM should establish criteria to be included in the RAA defining the obligations \nof LSEs to require that new data center loads have 15 year bilateral contracts with \nnew generation that do not permit any cost or risk shifting to other customers. \nThe contracts would be based on general terms and conditions in accordance \nwith tariff defined criteria with the cost and risk specifics defined by the data \ncenters and generators. \n• \nFor LSEs with data centers unable to make independent arrangements meeting \nthe criteria, PJM should run a full single clearing price auction using the BRA \ncapacity market clearing model for new data center load. LSEs would require \ndata centers to participate in the reliability backstop auction if they do not have a \nbilateral contract for new generation that meets the requirements of such \ncontracts. When the clearing process is complete, the LSEs would require that \ngenerators and data center loads enter into 15 year bilateral contracts that do not \npermit any cost or risk shifting to other customers. The contracts would be based \n \n \nunreasonable or unduly discriminatory or preferential because it lacks sufficiently clear and \nconsistent provisions regarding the study process related to the provision of transmission service to \nEligible Customers on behalf of large loads. We need not comprehensively address the \nCommission’s jurisdiction over other aspects of the addition of large loads to the transmission \nsystem at this time.”)."},{"page":5,"startToken":1505,"endToken":1821,"text":"- 5 - \non general terms and conditions in accordance with tariff defined criteria with \nthe cost and risk specifics defined by the data centers and generators. \n• \nPJM should establish curtailment obligations for wholesale service to data \ncenters during a defined transition period that would allow all data centers the \ntime to contract for new generation. \nThese requirements meet the goals of the Pledge and Principles and can be \nimplemented immediately. \nI. PROTEST \nA. The RBP Filing Has Not Been Shown Just and Reasonable. \nPJM faces the issue of how to address the massive and unexpected influx of data \ncenter load. While data center growth has occurred over five or more years, PJM has failed \nto address the impact of data centers on the PJM Capacity Market over the last four capacity \nauctions. PJM has made its RBP Filing only under direct pressure from the Commission and \nthe White House and the PJM governors, among others. It is clear that the current situation \nand the current tariff in PJM are untenable and therefore unjust and unreasonable. The \naddition of data center load has resulted in adding $29.4 billion to the cost of capacity, \nhigher energy costs, higher transmission costs, and a significant degradation of system \nreliability. Rather than directly addressing the issue of data center load, PJM’s RBP Filing \nproposes an extremely complex approach to this issue that unnecessarily undermines basic \nelements of the PJM market design. \nPJM’s RBP Filing fails to explain why PJM does not directly address the data center \nissue. PJM’s RBP Filing fails to explain why PJM imposes the costs of data centers on other \ncustomers and does not require data centers to pay the costs and bear the risks that they \nimpose on the system. PJM’s RBP Filing fails to explain why each of the significant changes \nto the fundamentals of the current capacity market design are required in order to address"},{"page":6,"startToken":1821,"endToken":2164,"text":"- 6 - \nthe data center issue. PJM fails to explain why the simple, focused Market Monitor proposal \nthat was presented in stakeholder discussions should not be adopted.8 \nPJM’s current approach to addressing data center load is not just and reasonable, as \ndemonstrated by the results of the last four Base Residual Auctions. It is not the \nfundamentals of the capacity market design that are at issue. It is not the fundamentals of \nthe energy market design that are at issue. It is the fact that PJM is currently allowing the \nrapid interconnection of large data center loads without having the capacity to serve those \nloads that makes the current PJM application of the rules unjust and unreasonable. The \nMarket Monitor has demonstrated that PJM’s approach has created a massive financial \nburden on all PJM customers.9 10 That demonstration does not include the additional \nimpact on energy market prices or on the costs of transmission. The RBP Filing in this \nmatter further demonstrates PJM’s own belated recognition that the application of the \ncurrent tariff rules is not just and reasonable. \nThe RBP Filing is inconsistent with the purpose of the Ratepayer Protection Pledge \nand Principles. That purpose is to ensure that data centers pay for their own costs and risks. \nPJM’s proposed RBP auction defines a shortfall that is based entirely on data center load yet \nassigns the costs and risks associated with meeting that shortfall to other PJM customers. \nPJM’s mistake, in this filing, is to propose unsupported changes to the fundamental \nmarket design while ignoring the actual data center issue which is that the data center loads \nare imposing significant costs and risks on other customers. There is a straightforward \n \n8 \nSee IMM, CIFP: Reliability Backstop, “Proposed reliability backstop auction design” (v6) (June 30, \n2026), included as Attachment A. \n9 \nSee Monitoring Analytics, LLC “Analysis of the 2027/2028 RPM Base Residual Auction – Part A,” \n(January 5, 2026). \n10 \nSee Monitoring Analytics, LLC, 2026 Quarterly State of the Market Report for PJM: January through June \n(August 13, 2026) Section 1: Introduction."},{"page":7,"startToken":2164,"endToken":2460,"text":"- 7 - \napproach that directly addresses the data center issue while maintaining the current market \ndesign. \nPJM’s RBP Filing is inconsistent with PJM’s fundamental market design. The \nelements of PJM’s market design that PJM seeks to change protect the public interest and \nhave worked to provide competitive results over a significant period. Additional rules are \nneeded to address the extraordinary issues presented by the speed and size of data center \nadditions. \nFederal and State government at the highest levels, with the explicit support of the \ndata centers themselves, have identified the issues and have identified acceptable solutions. \nBy their published standards, the RBP Filing is unacceptable. PJM’s RBP Filing violates the \nRatepayer Protection Pledge and Principles because the RBP Filing assigns the costs and \nrisks of data center load to other customers. \nThese facts, separately or together, should result in Commission rejection of the PJM \nRBP Filing. PJM should be directed to file tariff modifications within two weeks that would \ncreate a reliability backstop auction that facilitates the acquisition of capacity for those data \ncenters that commit to buying capacity and that have not otherwise bought capacity. \nThe goal should be a practical, implementable method for helping data centers to \nacquire and pay for capacity in order to help PJM and LSEs’ meet their obligations to ensure \nsystem reliability in the face of a massive onslaught of data center load, while ensuring that \ndata centers have access to power. \nB. The RBP Filing Is Deficient, Unjust and Unreasonable. \n1. The PJM RBP Filing would violate fundamental elements of the PJM \ncapacity market design. \nThe PJM RBP proposal would violate these fundamental elements of the PJM \ncapacity market design: \n• \nMust buy/must sell requirements in the capacity market \n• \nLSEs’ role in the capacity market \n• \nLocational capacity market design"},{"page":8,"startToken":2460,"endToken":2719,"text":"- 8 - \n• \nSingle clearing price auction design \n• \nMarket power mitigation rules \n• \nResponsibility for performance and for failure to perform \n2. PJM’s RBP Filing would reverse the core must buy/must sell \nobligations in the capacity market and convert to must buy/option to \nsell at highest price. \nThe PJM capacity market design is a must buy/must sell design in which all LSEs \nand all capacity owners must participate.11 12 The existing symmetrical design was intended \nto counter the market power of generation owners while allowing all LSEs to meet their \nobligation to have capacity to cover their load obligations. The PJM RBP Filing would \nreplace the must buy/must sell design with a must buy/option to sell at the highest price \ndesign. The proposed must buy/option to sell at the highest price design undoes the \nsymmetry and creates market power for generation sellers. The proposed must buy/option \nto sell at the highest price design provides no choice for buyers, but forces LSEs to pay the \nprices that result from PJM’s RBP process that fails to include any market power mitigation \nrules. \nPJM has failed to provide any explanation for why they propose to undermine this \ncore element of the capacity market and impose high prices on LSEs who have no ability to \naffect the price while allowing generators the option but not the obligation to sell at the \nhighest price. \n \n11 \n“Reliability Assurance Agreement Among Load Serving Entities in the PJM Region,” Article 7 § 7.2 \n& Schedule 8. \n12 \nPJM OATT Attachment DD § 6.6."},{"page":9,"startToken":2719,"endToken":3044,"text":"- 9 - \n3. PJM’s RBP Filing would inappropriately require LSEs to bear costs and \nrisks. \nPJM’s RBP Filing is inconsistent with PJM’s fundamental market design because it \nwould substitute a bilateral design for a competitive market design by making individual \nLSEs and their customers responsible for the costs of data center load. PJM’s repeated \nassertion that the PJM Capacity Market is primarily a bilateral market is not correct. That \nassertion is not supported by history. That assertion is not supported by the actual capacity \nmarket design and the actual functioning of the PJM Capacity Market. \nThe capacity market was originally implemented in 1999 at the request of the \nPennsylvania Public Utility Commission in order to prevent existing generation owners \nfrom exercising market power against new entrant competitive LSEs that needed to buy \ncapacity to meet their reliability obligation as defined in the RAA. That market power could \nbe exercised because the only source of capacity for a new entrant LSE to meet its reliability \nobligation was a bilateral contract with existing generation owners. Then, as now, the \nownership of capacity was highly concentrated and the generation owners had the ability to \nexercise market power in those bilateral negotiations. \nThe solution was a competitive capacity market that required all generation owners \nto sell their capacity at a competitive price and all LSEs to buy the capacity needed to meet \ntheir reliability requirements at a competitive price. The result was access to competitively \nprovided capacity that permitted competitive new entrant LSEs to compete with the \nincumbent utilities to meet load. As the capacity market evolved into the RPM design, the \nPJM capacity market design remains a must buy/must sell design in which all LSEs and all \ncapacity owners must participate.13 This design prevents both buyer side and seller side \nmarket power. \n \n13 \nLSEs may elect the Fixed Resource Requirement (“FRR”) alternative. See “Reliability Assurance \nAgreement Among Load Serving Entities in the PJM Region,” Schedule 8.1."},{"page":10,"startToken":3044,"endToken":3400,"text":"- 10 - \nPJM’s RBP Filing assigns the costs and risks of data center load to LSEs and their \nother customers based on this bilateral view of the capacity market. PJM supports its use of \na pay as bid auction design by asserting that it “more closely aligns with the economics and \nsettlement structures of bilateral contracts.”14 PJM’s proposal would reverse the advantages \nof the competitive capacity market and restore market power by assigning the costs of the \nRBP procurement to LSEs based on their share of the shortfall in the 2028/2029 Delivery \nYear based on forecasted growth in the large loads.15 Data center loads are not the \nresponsibility of the LSEs where the data centers choose to locate or of the other customers \nof the LSEs. Data center loads should pay their own costs and cover their own risks. PJM’s \nRBP Filing directly imposes the costs and risks of meeting data center load on LSEs and \ntheir customers. \nThe assignment of costs to LSEs with data center load is also inconsistent with the \nReliability Backstop Auction provisions of the tariff. The Reliability Backstop Auction tariff \nrules assign the costs of procuring backstop capacity to all LSEs in PJM on a pro rata basis \nbased on their daily unforced capacity obligations. PJM’s RBP Filing did not change this \nlanguage in Attachment DD, Section 16.4, as it applies to the Reliability Backstop Auction. \n4. The RBP Filing is inconsistent with the basic locational design of the \nPJM Capacity Market. \nThe RBP Filing is inconsistent with the basic locational design of the PJM Capacity \nMarket. The current locational Reliability Pricing Model (RPM) design was implemented in \n2007 because the capacity supply and demand conditions were very different by location \nwithin PJM. In 2007, the zones in Maryland and New Jersey were short capacity and \nwestern zones were long capacity and the transmission system did not permit the excess \n \n14 \nId. at 23–24. \n15 \nAttachment A - Revisions to the PJM Open Access Transmission Tariff and PJM Reliability \nAssurance Agreement at 18.3 Cost Allocation of RBP Charges, Credits, and Shortfall Charges \n(“Attachment A – Marked Tariff Records”)."},{"page":11,"startToken":3400,"endToken":3733,"text":"- 11 - \ncapacity in the west to solve the issues in the east. Maryland and New Jersey faced \nreliability issues and western zones did not. PJM created the locational RPM design in \nresponse to these basic structural facts. \nPJM’s explicit and conscious and unsupported failure to include locational \nrequirements in the RBP Filing creates the risk of repeating the experience of 2007. PJM’s \nfailure to address locational issues risks customers having to pay higher capacity prices in \nprice separated LDAs, customers having to pay for additional transmission and customers \nhaving to pay more for energy as more expensive local resources are required to actually \nmeet the data center load rather than the resources acquired in the RBP. PJM’s assertion \nthat it cannot predict CETO and CETL values for 15 years is irrelevant. That should not \nserve as a facile excuse for simply ignoring the critical locational dimension of the capacity \nmarket. Simply ignoring locational issues could result in very significant locational \nmismatches between resources and loads that are not resolvable even through transmission \nexpansion. There are clear solutions available for addressing the locational facts of PJM \nincluding requiring that the generation to serve a data center must be in the same LDA as \nthe data center. Ignoring locational realities is not an option. Ignoring locational realities \nwill create unintended consequences including the need to build transmission in the future \nand price separation in the capacity market that could mean even higher capacity prices in \nareas with data center load. \n5. The RBP Filing abandons single clearing price auction in favor of pay \nas bid. \nThe RBP Filing abandons the single clearing price auction design in favor of pay as \nbid, despite the complete failure to explain why economists’ consensus view of this issue is \nignored.16 Pay as bid is inefficient and does not facilitate competition. After deciding to \nabandon basic competitive market design PJM then uses its chosen pay as bid structure as a \n \n16 \nRBP Filing, Attachment C (Croop Affidavit) at 21."},{"page":12,"startToken":3733,"endToken":4094,"text":"- 12 - \nreason for failing to have market power mitigation rules. PJM fails to justify using pay as \nbid in place of the competitive and efficient single clearing price approach that has been a \nfundamental part of the PJM market design since its inception. \nUnder PJM’s proposed pay as bid structure an RBP seller, if selected in the \nprocurement process, will be paid its RBP sell offer. PJM also proposes to not use “market \npower screening or mitigation measures.”17 It should be unacceptable that PJM, at a time of \nsevere supply shortage, would propose to not use the standard market power screening \nthat is used in all PJM capacity auctions. \nPay as bid auctions do not provide an incentive for sellers to reveal their costs while \na uniform price auction does. For example, if Plant A has a lower cost than Plant B and both \ngenerators are expected to clear, under pay as bid Plant A has an incentive to offer above its \nactual cost and to guess at the clearing price. In a uniform price auction, Plant A can offer \nits cost and still receive the higher clearing price in the case that Plant B is marginal. That is \nthe efficient and competitive outcome. By proposing a pay as bid auction design with no \nmarket power screening, RBP market sellers have a strong incentive to offer above their \ncost. PJM defends using pay as bid pricing rather than uniform pricing that is used in PJM’s \nRPM auctions by asserting that pricing outcomes are less likely to serve as market signals \nand that the pay as bid approach “more closely aligns with the economics and settlement \nstructures of bilateral contracts.”18 PJM misses one of the important aspects of having a \ncompetitive capacity auction that reveals prices. Competitive auctions provide a price \nsignal to both parties engaged in bilateral contract negotiations. Finally, PJM argues that \nuniform pricing would require offers to be normalized using potentially complex and \nsubjective assumptions because the RBP capacity product is not uniform due to differences \nin contract duration, commercial operation dates, ELCC accreditation and changes in the \n \n17 \nId. at 32. \n18 \nId. at 23–24."},{"page":13,"startToken":4094,"endToken":4403,"text":"- 13 - \nELCC accreditation over the 15 year period.19 The whole point of capacity accreditation and \ncalculating a levelized cost offer is to provide a homogenous product at a comparable price \nthat conveys all necessary information to the buyer and the buyer is indifferent between \npurchasing the product from Plant A versus Plant B. PJM’s own evaluation of which offers \nare better than others depends on calculating the price for a product. PJM is in fact using \ncomplex and subjective assumptions to evaluate competing offers. \n6. The PJM RBP Filing fails to address market power. \nThe PJM RBP Filing explicitly and entirely fails to address market power despite the \nfact that the entire PJM Capacity Market is characterized by endemic market power and \ndespite the fact that the RBP auction design creates market power by establishing an \ninelastic demand for capacity and a maximum price that is not really a maximum price. \nEffective market power mitigation is needed now more than ever. PJM’s only justification \nfor failing to address market power is that it is difficult to design market power mitigation \nrules when there is a pay as bid design. The pay as bid design is PJM’s choice. PJM’s \nrationale for pay as bid is that it looks more like a bilateral market. PJM fails to note a key \nfeature of bilateral markets. Bilateral markets have two sides. PJM’s RBP simply assigns \ncosts to LSEs and gives LSEs no voice in the price. The result is not a bilateral market but a \none sided market with extreme market power conferred on generators. \nPJM has chosen an inefficient and noncompetitive pay as bid design despite the \nnearly unanimous recommendation of economists that in turn makes market power \nmitigation more difficult. The answer is straightforward. Use a single clearing price auction \nwith clear market power mitigation rules. \n \n19 \nId. at 25."},{"page":14,"startToken":4403,"endToken":4764,"text":"- 14 - \n7. The RBP Filing shifts ELCC risk from generators to customers. The RBP \nfiling shifts the risks of generators failing to perform to customers. \nPJM’s RBP rules would permit generators to sell more capacity than they actually \nhave and to do so without penalty for overstating capacity. PJM’s RBP rules allow RBP sell \noffer UCAP MW values up to 120 percent of the maximum preliminary ELCC class rating \nfor 2028/2029 through the last posted Delivery Year.20 This will overstate the RBP cleared \nMW and require customers to pay for nonexistent capacity. More generally, PJM proposes \nto inappropriately shift ELCC related risk from generators to customers.21 Generator \nperformance risk is an investor risk and not a customer risk. One of the benefits of markets \nis that performance risk is assigned to generators because they are responsible for unit \nperformance. \nThere is no analytical or market basis for permitting generators to oversell capacity \nin the RBP process. In fact, as PJM pointed out recently, increased data center load results in \nreduced ELCC values for most technology types.22 Regardless of expected ELCC changes, \ngenerators should sell only the amount of their current accredited capacity and generators \nshould bear the risk of changes in accredited value. \nUnder PJM’s RBP Filing, generators are not required to cover shortfalls due to \nchanges in the ELCC ratings. The generators will not be paid for the shortfall in capacity \nbut there are no shortfall charges for failing to provide what was sold.23 This shifts the \n \n20 \nAttachment A – Marked Tariff Records at Attachment DD, 18.5(e)(i). \n21 \nShortfalls due to decreases in the ELCC ratings are not subject to RBP Shortfall Charges. See RBP \nFiling, Attachment A – Market Tariff Records, Attachment DD, 18.6(d). \n22 \nInstalled Reserve Margin (IRM), Forecast Pool Requirement (FPR), and Effective Load Carrying \nCapability (ELCC) for 2029/2030 BRA at 6 and 16, MRC Meeting Materials Item 3, Markets and \nReliability \nCommittee \n(August \n19, \n2026). \n \n23 \nRBP Filing, Attachment A – Market Tariff Records, Attachment DD, 18.6(c) through (d)."},{"page":15,"startToken":4764,"endToken":5067,"text":"- 15 - \nELCC accreditation risk to load which has to pay for the additional supply to cover the \nshortfall. This transfers the risk of non-delivery to the load and unfairly requires the load to \npay for the shortfall in needed capacity rather than requiring the RBP seller to provide the \ncapacity. \n8. The RBP Filing is inconsistent with the capacity market approach to \npenalties for performance. \nThe RBP Filing is inconsistent with the capacity market approach to penalties for \nperformance. \nRBP Shortfall Charges are defined in the PJM proposed Tariff, Attachment DD, \nSections 18.6(c) through 18.6(e). PJM proposed Tariff, Attachment DD, section 18.6(d) states: \nRBP Resources with RBP UCAP MW committed through the \nReliability Backstop Procurement that are unable to meet its full \nRBP UCAP MW commitment due to not achieving commercial \noperation by the first Delivery Year of the RBP commitment shall \nbe subject to RBP shortfall charges for the committed RBP UCAP \nMW until the resources achieves commercial operation, for up to \nthree years. \nThis proposed Tariff language unnecessarily restricts the applicability of charges to a \nnarrow, specific reason, is vague about the timing of the charges, limits the charges to three \nyears, and shifts the risk from resource owners to customers. The PJM proposed criteria for \ndefining RBP Shortfall Charges have not been shown to be just and reasonable and should \nbe rejected. PJM’s proposed criteria for defining RBP Shortfall Charges are also vague and \nunenforceable. PJM has not explained why the RBP penalties vary so significantly from the \ncurrent RPM rules. \nDeficiency charges in the current RPM rules are assessed due to a failure to satisfy a \ncommitment “for any reason,” such as derates and retirements whereas the proposed RBP \nShortfall Charge would only apply for a specific reason, “due to not achieving commercial"},{"page":16,"startToken":5067,"endToken":5396,"text":"- 16 - \noperation.”24 For example, if a generation project configuration and MW change \nsignificantly but it still achieves commercial operation by the delivery year, it is not clear \nwhether RBP Shortfall Charges would apply. If a generation resource achieves commercial \noperation but then has a catastrophic failure and retires halfway through the 15 year term, it \nappears that no RBP Shortfall Charges would apply. \nUse of the term commercial operation instead of the more precise tariff defined \ncommencement of Interconnection Service limits the applicability even more so. Also, the \nterm commercial operation is generally not a term applied to demand resources and DER \naggregation resources. As RBP Resources under the PJM proposal include demand \nresources and DER aggregation resources, it is not clear how the RBP Shortall Charges \nwould apply to these resource types. In fact, in defining the eligibility criteria for RBP \nResources in proposed Tariff, Attachment DD, Sections 18.5(a)(i), PJM distinguishes \ndemand resources and DER aggregate resources as being registered and under a contract to \nperform versus having a commercial operation date prior to June 1, 2032. PJM does not \nexplain why this same distinction is not included in the RBP Shortfall Charge provision. \nPJM states that RBP Shortfall Charges would apply if commercial operation is not \nachieved by the first Delivery Year of the RBP commitment. PJM OATT, Attachment DD, \nSection 8 Capacity Resource Deficiency Charges, which is a parallel charge to the RBP \nShortfall Charge, clearly states that the charge is applicable when committed MW are \nunable or unavailable to deliver unforced capacity “for all or any part of such Delivery \nYear” and likewise uses the term “start of the Delivery Year” when describing the timing of \nthe failure to meet RPM commitments.25 The PJM proposed Tariff language lacks specificity \nin defining the timing of the penalty assessments. PJM does not explain or support the \ndifferent treatment for RBP resources. \n \n24 \nOATT Attachment DD § 8.1. \n25 \nOATT Attachment DD § 8."},{"page":17,"startToken":5396,"endToken":5704,"text":"- 17 - \nUnder the PJM proposal, the RBP Shortfall Charges are limited to three years. In the \ntransmittal letter, page 61, PJM states that the reason for the limitation on the RBP Shortall \nCharges is to reduce barriers to entry. Limiting the penalties to three years of the 15 year \nterm results in shifting the risk from resource owners to LSEs. PJM’s reasoning is not logical \nor meaningful. The fact that a generator in a market has risks is always a barrier to entry. \nBarriers to entry are not bad by definition. PJM’s entire tariff could be reasonably \nconsidered to be a barrier to entry. It is not PJM’s role to help generators by shifting their \nrisks to customers. Yet that is exactly what PJM proposes to do. \nPJM proposed Tariff, Attachment DD, Sections 18.6(d)(i) states: \nAn RBP Resource that is a generation or Energy Storage Resource \nand is unable to meet expected commercial operation date solely \ndue to Network Upgrades shall be excepted from RBP shortfall \ncharges if the RBP Resource successfully demonstrates readiness \nthrough test energy and seeks interim deliverability. \nThis exception for unavailability due to Network Upgrades erodes the penalty \nassessment and again results in shifting the risk from resource owners to LSEs and their \ncustomers. \nThe RBP Filing is also inconsistent with a logical approach to addressing the data \ncenter issues: \n• \nFails to distinguish data center load from other loads \n• \nFails to match energy supply and data center demand \n• \nFails to provide revenue certainty for full generation revenue requirement \n• \nFails to include a consistent definition of capacity that can meet data center \nload \n• \nFails to include effective, targeted penalties for failure to perform \n• \nFails to include a logical market clearing mechanism \n• \nFails to update the maximum price used in the RBP \n• \nFails to reasonably assign risk and the associated credit and collateral"},{"page":18,"startToken":5704,"endToken":6093,"text":"- 18 - \n1. PJM proposes to include all large loads rather than just data center load. \nThe ostensible goal of the RBP Filing is to address the data center issue. Addressing \nthe data center issue requires separately identifying and providing special rules applicable \nto LSEs serving data center loads. Special rules are justified because there are extraordinary \ncircumstances specifically applicable to data centers.26 Data centers are requesting \nunusually expedited service and at unusually elevated volumes, and significant efforts are \nbeing made to accommodate their extraordinary demands. Large loads in the nature of \ncustomers who have a long history of taking service from the system are not responsible for \nthe data center issue. These customers are not seeking the sudden addition of large loads on \nan expedited basis outside of longstanding historical norms. It is necessary and appropriate \nto craft rules that specifically apply to LSEs serving data centers for the same reason that \nhyperscalers representing data centers are the ones affirming the Pledge. The inclusion of \nall large loads within the scope of the RBP Filing is unjust and unreasonable, and is unduly \ndiscriminatory, because large loads that are not data centers do not present the \nextraordinary circumstances that the RBP Filing should address. \n2. The RBP Filing fails to match supply and demand for energy \nThe RBP Filing is inconsistent with matching the supply and demand for energy. \nPJM makes no effort to match the duration of supply with the duration of demand. PJM \nfails to recognize or address these issues. Data center demand is 8,760 hours per year. Since \na four hour battery is an acceptable form of resource under the RBP, there is a significant \n \n26 \nSee 16 U.S.C. § 824d; TranSource, LLC v. PJM Interconnection, L.L.C., 168 FERC ¶ 61,119, 61636 \n(2019) (“The courts have consistently upheld this longstanding approach to undue \ndiscrimination.”) citing, e.g., Complex v. FERC, 165 F.3d 992, 1012 (1999); Advanced Energy v. \nFERC, 860 F.3d 656, 670–71 (2017); Transmission Agency v. FERC, 628 F.3d 538, 549 (2010) (“A rate \nis not 'unduly' preferential or 'unreasonably' discriminatory if the utility can justify the disparate \neffect. The court will not find a Commission determination to be unduly discriminatory if the entity \nclaiming discrimination is not similarly situated to others (internal quotations and citations \nomitted).”)."},{"page":19,"startToken":6093,"endToken":6436,"text":"- 19 - \nmismatch between the supply of energy from the battery and the demand for energy from \nthe data center, plus the charging demand of the battery. The same issue exists for \nstandalone solar resources. The result of this mismatch will be higher energy prices for all \nPJM customers because higher cost resources will need to be dispatched to meet the \ndemand for energy. \n3. The RBP Filing is inconsistent with the requirement to provide revenue \ncertainty to new generation for 15 years. \nThe RBP Filing is inconsistent with the requirement to provide revenue certainty to \nnew generation for 15 years. The RBP Filing addresses only the capacity cost component of \nthe total revenue requirement for building new capacity. The contract for differences \naddresses only the price of capacity. The RBP pricing entirely ignores net revenue from the \nenergy and ancillary services markets and therefore ignores more than half the revenue for \na new CC resource. \n4. The RBP Filing includes inconsistent definitions of the capacity that \ncan satisfy the requirements to meet the data center load. \nThe RBP Filing does not have a consistent definition of capacity. While the stated \nintent of the Principles and of the RBP Filing is to have 15 year capacity to meet the shortfall \nin supply resulting from data center demand, the RBP Filing allows inferior capacity to \ndisplace such 15 year capacity. The RBP Filing includes very different definitions of the \ncapacity that can satisfy the requirements to meet the data center load. The RBP auction \nrequires 15 year contracts. The RBP Filing also allows five year bilateral contracts to meet \nthe same obligation under the RPB offset option. The RBP auction has a stronger definition \nof what constitutes new capacity than the RBP offset definition. The RBP Filing creates \nstrong incentives to provide inferior and shorter term capacity to meet the 15 year demand. \nThe RBP Filing creates strong incentives to claim capacity that is not actually new capacity \nto meet data center demand. PJM provides no reason for these weaker standards for RBP \noffset MW."},{"page":20,"startToken":6436,"endToken":6769,"text":"- 20 - \nThe criteria for qualifying to be an RBP resource are defined in the PJM proposed \nTariff, Attachment DD, Section 18.5(a) through (d). PJM’s proposed criteria include uprates, \ndemand resources, and DER aggregation resources. The goal should be to support new \ngeneration and to prevent gaming of the rules by reclassifying existing capacity resources \nas new. The definition should ensure that all cleared capacity represents investment in new \nphysical supply rather than redefining existing resources. PJM’s proposed criteria fail to do \nthis. \nPJM’s criteria in proposed Tariff, Attachment DD, Section 18.5(b) uses the \ncapitalized term Installed Capacity, but there is no proposed definition or definition in the \nexisting tariff. \nThe criteria for qualifying for RBP Offset UCAP MW are defined in PJM proposed \nTariff, Attachment DD, Section 18.2. These criteria differ from the criteria to qualify for an \nRBP resource in several ways, including allowing incremental capacity created by the \nutilization of Surplus Interconnection Service; incremental CIRs or UCAP due to fuel \nswitching; Planned Demand Resources and Planned DER Capacity Aggregation Resources. \nPJM fails to explain why capacity qualifying for RBP Offset UCAP MW are held to a \nweaker standard than RBP resources given that both are being used to satisfy the reliability \nshortfall. RBP offset rules also only require 5 year contracts for bilateral contracts and self \nsupply versus the 15 year term for the RBP. \nThe problem is that PJM proposes to treat RBP offset capacity as equivalent to RBP \nsupply for purposes of reducing the regional reliability requirement, even though the two \nhave materially different contractual protections and performance obligations. Under PJM’s \nRBP Filing, an offset does not need to demonstrate that it provides a substitute contribution \nto resource adequacy while reducing the RBP procurement target by that amount. The \nconcern is particularly acute for DR and DER as offset MW because their UCAP \ncontribution is dependent upon operating conditions, dispatch availability, customer \nparticipation and other factors that differ from the characteristics of conventional \ngeneration."},{"page":21,"startToken":6769,"endToken":6927,"text":"- 21 - \nThere is an asymmetry. PJM is willing to reduce a 15 year regional procurement \nobligation based on offset arrangements that require only five years of contractual \ncommitment. The Commission must require PJM to justify why five years of capacity is \nsufficient to offset a procurement obligation that otherwise would be satisfied through a 15 \nyear commitment. For DR and DER, the concern is even more pronounced because the \ncommitment is to provide a specified demand reduction or DER capability, rather than to \nmaintain a physical generating asset for the duration of the RBP term. \nAn offset should be required to demonstrate durable capacity availability for the \nsame period over which it displaces RBP procurement, or PJM needs to justify why a \nshorter commitment provides equivalent reliability value. All capacity that addresses the \nshortfall should be required to meet the same conditions. \nTable 1 summarizes the different requirements for RBP capacity and the three types \nof offset capacity."},{"page":22,"startToken":6927,"endToken":7384,"text":"- 22 - \nTable 1 The requirements for RBP capacity and offset capacity \n \n5. DR as capacity to meet demand of data centers \nPermitting DR and DER to serve as RBP supply creates capacity that is materially \ninferior to generation capacity resources. Committed generation is required to participate in \nPJM’s Day-Ahead Energy Market and make itself available for economic dispatch. In \ncontrast, committed DR is only required to enroll in PJM’s Annual Demand Response \nprogram which means that its reliability benefits are only available when PJM invokes \nemergency procedures. This is analogous to permitting RBP Offset generation to classify its \ncommitted ICAP as maximum emergency requiring PJM to invoke emergency procedures \nin order to access its reliability benefit. \nAllowing new load to serve as its own offset through enrollment as Annual Demand \nResponse further allows the new load to circumvent curtailment under IRAS. IRAS \nGen\nDR and DER\nBilateral\nSelf Supply\nCSP or DER \nAggregator\nCOD or \nunder contract date\nNo later than June 1, \n2032\nNo later than June 1, \n2032\nNo later than June 1, \n2032\nNo later than June 1, \n2032\nNo later than June 1, \n2032\nNew build\nNew ICAP, new MFO, \nsupported by new or \ntransferred CIRs from a \ndeactivated resource or \na resource that \nannounced deactivation \nas of April 10, 2026\nNA\nNot clearly defined. \nIncludes transferred \nCIRs from a deactivated \nresource or a resource \nthat has announced \ndeactivation as of April \n10, 2026\nNot clearly defined. \nIncludes transferred \nCIRs from a deactivated \nresource or a resource \nthat has announced \ndeactivation as of April \n10, 2026\nNA\nUprate\nNew ICAP, new MFO , \nsupported by new or \ntransferred CIRs\nNA\nNew ICAP, supported \nby an increase in CIRs \n(does not specify new \nor transferred)\nNew ICAP, supported \nby an increase in CIRs \n(does not specify new \nor transferred)\nNA\nIncremental capacity \nother than uprates\nNot allowable\nNA\nAllowable for Surplus \nInterconnection Service; \nUCAP or CIR increase \ndue to fuel switching\nAllowable for Surplus \nInterconnection Service; \nUCAP or CIR increase \ndue to fuel switching\nNA\nRepowering\nDeactivated, or \nannounced \ndeactivation, on or \nbefore April 10, 2026.\nNA\nDeactivated prior to \nApril 10, 2026\nDeactivated prior to \nApril 10, 2026\nNA\nTerm\n15 year\n15 year\nAt least 5 delivery years At least 5 delivery years 2028/2029 Second IA \nthrough 2032/2033\nLoad matching\nMatched with load that \nhas an executed electric \nservice agreement or \ntransmission service \nagreement, indicating \nthat the load will be \ncoming online in the \n2027/2028 or 2028/2029 \nDelivery Year\nMatched with load that \nhas an executed electric \nservice agreement or \ntransmission service \nagreement, indicating \nthat the load will be \ncoming online in the \n2027/2028 or 2028/2029 \nDelivery Year\n2028/2029\nRBP Offset UCAP MW\nRBP Supply\nRequirement"},{"page":23,"startToken":7384,"endToken":7735,"text":"- 23 - \ncurtailments occur prior to pre-emergency Demand Response. The new load enrolled as its \nown DR offset provides a means to subordinate its curtailment relative to curtailment \npriority under IRAS. \nPJM's proposal to permit a new data center to satisfy its own RBP obligation by \nenrolling the load as an Annual Demand Resource is flawed because it allows the load to \nreceive credit against the RBP requirement without providing a reliability commitment \nequivalent to the capacity that the RBP otherwise would procure. Under the RBP Filing, a \nnew load can use Annual Demand resource participation as an RBP offset through the \n2032/2033 Delivery Year whereas a committed RBP resource would be subject to a 15 year \nterm. PJM therefore would permit a relatively short term demand response commitment to \ndisplace a capacity procurement that otherwise would provide 15 years of committed \ncapacity. The reliability value of that DR also differs fundamentally from that of committed \ngeneration. DR is an emergency resource whose reliability contribution is realized through \nPJM’s direction to curtail load under emergency procedures, whereas a committed \ngeneration resource can be economically dispatched when needed, providing a continuing \nsource of energy without requiring PJM to invoke emergency measures. Allowing the new \ndata center to designate its own load as Annual DR further creates an opportunity to avoid \nthe curtailment obligation that would otherwise apply to the load under PJM’s Interim \nResource Adequacy Service (“IRAS”). In effect, the data center can transform a reliability \nobligation imposed on an inadequately supplied large load into a self-designated RBP \noffset, while providing PJM with a demand side resource whose availability is dependent \non emergency curtailment rather than an economically dispatchable supply resource. This \nraises a fundamental question. PJM has not demonstrated that such DR provides reliability \nvalue comparable to the 15 year committed capacity that it displaces, particularly when the \nload itself is the entity receiving the benefit from the offset. PJM’s own description of the \nRBP confirms that the procurement is intended to secure a new capacity for up to 15 years \nwhile qualifying offsets are used to reduce the procurement target."},{"page":24,"startToken":7735,"endToken":8111,"text":"- 24 - \nConsider an LSE with a 1 GW data center that becomes subject to the RBP because \nits incremental load contributes to PJM’s identified resource adequacy need. Under PJM's \nproposal, the data center could enroll its entire load as an Annual Demand Resource and \nuse the resulting UCAP value as an RBP offset. If the 1 GW load received 1 GW of \nqualifying DR offset credit, the data center would effectively eliminate its RBP obligation \nwithout PJM procuring a new generation resource to serve that capacity. Yet, the DR \narrangement would provide a materially different commitment from the RBP capacity it \ndisplaces. The DR commitment would extend only through the 2032/2033 Delivery Year \neffectively, a five delivery year commitment, while an RBP resource would be committed \nfor 15 years. Moreover, PJM cannot access the DR capability in the ordinary course through \neconomic dispatch. The reliability benefit is available only when PJM invokes its emergency \nprocedures and requires the data center to curtail. A generation resource procured through \nthe RBP, by contrast, can be economically dispatched when needed and can provide energy \nwithout requiring PJM to declare an emergency and order the data center offline. The \nproposal therefore permits the 1 GW data center to substitute a relatively short duration, \nemergency only curtailment obligation, for the 15 year capacity commitment that otherwise \nwould be procured through the RBP. It also allows the data center to avoid the curtailment \nto which it would otherwise be subject under IRAS by designating its own load as an RBP \noffset. In substance, the proposal allows the large load to satisfy the reliability obligation \ncreated by its own demand by making itself a demand response resource, even though that \nresource provides a fundamentally different and less durable reliability product than the \ncapacity procurement it displaces. \n6. The proposed RBP process is not consistent with the cost minimizing \nprinciples used for clearing energy and capacity markets in PJM today. \nThe proposed RBP auction clearing process is not consistent with the cost \nminimizing principles used for clearing energy and capacity markets in PJM today. The \nselection process lacks a clearly defined objective and favors resources that will offer to \nprovide capacity with a commercial operation date in 2028/2029 over resources that need"},{"page":25,"startToken":8111,"endToken":8496,"text":"- 25 - \nadditional time to achieve commercial operation even when the later resources are less \ncostly and have better reliability characteristics.27 The RBP’s use of a pay as bid approach \ncoupled with the failure to include market power mitigation will result in the exercise of \nmarket power. The RBP Filing includes a levelized cost calculation that PJM has not \nsupported or explained. PJM’s defines the Levelized Cost ($ per MW-day) as the Present \nValue of future revenues (Offer Price*UCAP Offered) divided by the sum of discounted \noffered UCAP MW values.28 PJM proposed to use a discount rate equal to 9.5 percent after \ntax average weighted average cost of capital for discounting the revenues and UCAP MW. \nDiscounted cash payments are well understood and frequently used for comparing \nrevenues or investment opportunities spread over future years, but it is not clear what \ndiscounted UCAP MW mean. For example, $100 in five years is worth $63.52 today. \nApplying PJM’s logic and discount rate, 100 MW of UCAP in five years has a discounted \nvalue of 63.52 MW. PJM does not explain the meaning of a discounted MW. \nA better approach for comparing offers with varying UCAP MW would be to divide \nthe levelized annual revenue from the RBP payments by the average UCAP MW. The \nlevelized annual revenue is equal to the present value of the RBP payments multiplied by a \ncapital recovery factor (CRF). 29 The average UCAP MW represents the expected UCAP MW \nover a time period unlike the discounted UCAP MW which understates the expected UCAP \n \n27 \nAttachment A - Revisions to the PJM Open Access Transmission Tariff and PJM Reliability \nAssurance Agreement at 18.5 The Reliability Backstop Procurement Process (“Attachment A – \nMarked Tariff Records”).) \n28 \nUnder the PJM ‘s proposed approach, sellers of RBP capacity provide PJM offer price in $/MW-day \nand offer MW for every delivery year between the expected commercial operation date and the \nmaximum term of 15 years that does not extend beyond the 2042/2043 Delivery Year. \n29 \nA CRF is used to convert a present day dollar amount into an equivalent level payment over a \nperiod of years. PJM currently uses CRF factors to determine capital recovery payments for black \nstart generators and incremental investments in the definition of avoidable cost for capacity \nresources."},{"page":26,"startToken":8496,"endToken":8826,"text":"- 26 - \nMW. This approach also does not give preference to resources that need less time to achieve \ncommercial operation. \nThe proposed RBP procurement selection process lacks a clearly defined objective. In \nthe PJM annual capacity market, the objective is to minimize the total procurement cost to \nmeet the reliability requirement. The objective is met after evaluating all feasible tradeoffs. \nThis is accomplished through a linear optimization algorithm. The RBP procurement \napproach first ranks the offers based only on expected commercial operation date. A sell \noffer with an earlier commercial operation date is preferred over a project with lower cost \nand better reliability characteristics, but a later commercial operation date. For example, the \nproposed RBP clearing logic would choose a demand response alternative with an earlier \ncommercial operation date and a higher price over a combined cycle with a later \ncommercial operation date and a lower price. The RBP iterative selection approach does not \ninclude the fundamental cost minimization principles that are essential to a competitive \nmarket and are the basis for capacity procurement in the annual PJM Capacity Market. \nAfter ordering all received offers based on the expected commercial operation date, PJM \niteratively selects and unselects the sell offers to select a first combination of sell offers that \nexceeds the shortfall such that the combined levelized cost falls below the maximum \nwillingness to pay. PJM does not exhaustively examine any more offers in the ordered list \nto explore the potential for finding a cheaper combination. Even under PJM’s purported \nlevelized cost metric, the combination chosen by PJM will not necessarily be the least cost \nsolution. \nPJM fails to provide any meaningful support for this ineffective and inefficient \napproach. \nPJM’s levelized cost calculation does not correctly reflect the cost to provide capacity \nand will distort the selection process. Through discounting the future MW in the levelized \ncost calculation and through ordering the resource for selection based on the earlier \ncommercial operation date, PJM would give preference to expensive offers with lower"},{"page":27,"startToken":8826,"endToken":9160,"text":"- 27 - \nUCAP MW in the earlier years over cheaper offers with higher UCAP MW in the later \nyears. \n7. PJM failed to update the maximum price calculation \nPJM failed to update the calculation of energy market net revenues that is used to \noffset Gross CONE to calculate the Net CONE value used as the maximum price in the RBP \nof $555/MW-day. Based on the forward looking method used to calculate the $555/MW-day \nnumber, net revenues are significantly higher than the net revenues used by PJM. As a \nresult, PJM has significantly overstated the maximum price for the RBP. \nPJM failed to explicitly address energy market net revenues in the RBP Filing. \nHowever, the price cap of $555/MW-Day UCAP used by PJM in the RBP Filing was based \non a very specific value of energy market net revenues. \nNet CONE is equal to Gross CONE less energy and ancillary net revenues (EAS). If \nEAS increases, Net CONE decreases. At the August 22, 2025, Market Implementation \nCommittee, PJM presented Net CONE values for each CONE area as well as the RTO, and \nspecified that the dates of the forwards were the 30 trade dates that conclude in August \n2025.30 The CONE Area and RTO Net CONE values are the same as the Net CONE values \nshown by zone in the Marzewski Affidavit in Table 3.31 \nThe $555/MW-Day price cap of the RBP is the RTO Net CONE based on those \nAugust 2025 forward prices. The August 2025 forwards are now a year out of date. Forward \nprices have substantially increased since August 2025. Comparing forward prices for the \n \n30 \nSkyler Marzewski, CONE Operating Parameters for Net EAS, and Net CONE Updates. Market \nImplementation Committee. (August 22, 202). The date of these forwards is: 30 trade dates that \nconcluded in August 2025. \n31 \n2025 Periodic Review of Variable Resource Requirement Curve Shape and Key Parameters, \nAffidavit of Skyler Marzewski in Docket No. ER26-455-000, (“Quad Review Filing”). (November 7, \n2025) (“Marzewski Affidavit”)."},{"page":28,"startToken":9160,"endToken":9443,"text":"- 28 - \n2028/2029 Delivery Year as of August 1, 2025, to August 1, 2026, average hourly Western \nHub LMPs have increased by $14/MWh, or 24 percent. \nIf forwards are 24 percent higher, EAS is higher, and point A of the VRR Curve = \nmax[(1.15 x Gross CONE - 0.75 x Net E&AS) or (0.2 x Gross CONE)] is $473/MW-Day \nUCAP, not $555/MW-Day UCAP.32 \nPJM should be required to use an accurate maximum price, based on PJM’s \napproved method. \nC. Rejecting the RBP Filing Would Allow the Commission to Direct and \nAppropriate Remedy. \n1. The Current Rules Are Inadequate to Address Prevailing Market \nConditions. \nThe Market Monitor has extensively documented the fact that the application of the \ncurrent tariff is unjust and unreasonable and produces results that are not competitive.33 34 \n2. The Record Provides Sufficient Information for the Commission to \nImmediately Issue a Remedial Directive that Protects Reliability and \nAffordability. \nUpon issuing a finding that the current rules are unjust and unreasonable, the \nCommission can, on the basis of the existing record, direct PJM to implement a remedy \n(“Remedial Directive”). The Remedial Directive is based on the Market Monitor Proposal \n(Attachment A), but streamlined to allow for immediate issuance of a directive that \nincludes the core concepts while deferring full consideration and approval of the details. \n \n32 \nSee Technical Appendix, included as Attachment B to this filing, for more details on the calculation. \n33 \nSee Monitoring Analytics, LLC “Analysis of the 2027/2028 RPM Base Residual Auction – Part A,” \n(January 5, 2026). \n34 \nSee Monitoring Analytics, LLC, 2026 Quarterly State of the Market Report for PJM: January through June \n(August 13, 2026) Section 1: Introduction."},{"page":29,"startToken":9443,"endToken":9735,"text":"- 29 - \nThe Remedial Directive should direct that PJM file, within two weeks, rules and \nprocedures with the following elements: \n• \nPJM should, working with LSEs and EDCs, immediately identify data center \nload not interconnected by June 1, 2026, and remove it from RPM capacity \nmarket auctions. \n• \nPJM should establish criteria to be included in the RAA defining the obligations \nof LSEs to require that new data center loads have 15 year bilateral contracts with \nnew generation that do not permit any cost or risk shifting to other customers. \nThe contracts would be based on general terms and conditions in accordance \nwith tariff defined criteria with the cost and risk specifics defined by the data \ncenters and generators. \n• \nFor LSEs with data centers unable to make independent arrangements meeting \nthe criteria, PJM should run a full single clearing price auction using the BRA \ncapacity market clearing model for new data center load. LSEs would require \ndata centers to participate in the reliability backstop auction if they do not have a \nbilateral contract for new generation that meets the requirements of such \ncontracts. When the clearing process is complete, the LSEs would require that \ngenerators and data center loads enter into 15 year bilateral contracts that do not \npermit any cost or risk shifting to other customers. The contracts would be based \non general terms and conditions in accordance with tariff defined criteria with \nthe cost and risk specifics defined by the data centers and generators. \n• \nPJM should establish curtailment obligations for wholesale service to data \ncenters during a defined transition period that would allow all data centers the \ntime to contract for new generation. \nThese requirements can be implemented immediately and can be relied upon to \nmeet the goals of the Pledge and Principles."},{"page":30,"startToken":9735,"endToken":10192,"text":"- 30 - \nThe Commission has exclusive jurisdiction over the terms and conditions of \nwholesale power sales and the bulk power grid.35 The capacity obligation of LSEs to \nsupport resource adequacy is a term and condition of wholesale power sales subject to the \nCommission’s exclusive jurisdiction.36 37 The Remedial Directive applies to LSEs and the \nterms and conditions necessary to meet capacity obligations to PJM, and these terms cannot \nbe changed by States.38 The Supreme Court has determined that Federal regulation in this \nfield preempts state regulation. 39 The Remedial Directive does not regulate retail power \nsales. The Commission’s jurisdiction to determine whether LSEs have met capacity \nobligations related to resource adequacy does not intrude on the jurisdiction over \ngeneration reserved to the States.40 The Commission initiated a proceeding to address \n \n35 \nSee 16 U.S.C. § 824. \n36 \nSee Hughes v. Talen Energy Mktg., LLC, 578 U.S. 150, 163 (2016) (“We agree with the Fourth \nCircuit’s judgment that Maryland’s program sets an interstate wholesale rate, contravening the \nFPA’s division of authority between state and federal regulators. As earlier recounted, … the FPA \nallocates to FERC exclusive jurisdiction over “rates and charges . . . received . . . for or in connection \nwith” interstate wholesale sales. §824d(a). Exercising this authority, FERC has approved the PJM \ncapacity auction as the sole rate setting mechanism for sales of capacity to PJM, and has deemed \nthe clearing price per se just and reasonable”). \n37 \nRAA Article 7. \n38 \nSee Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 972 (1986) (“[I]n formulating rates \nover which it has exclusive jurisdiction, FERC ruled that the NFA and AA should be treated as \nallocating 22.5% of the entitlement power of the Tapoco-Nantahala system to Nantahala's \ncustomers and 77.5% of that power to Tapoco's customer. That allocation, reflected as it is in a filed \nrate, must be respected by NCUC. If, as a result, Nantahala needs to purchase additional power \nfrom some nonentitlement source, that need is a reasonable one.’). \n39 \nSee id (state action targeting rates for capacity preempted by federal occupation of the field), citing \nEPSA, 577 U.S. 260, 288 (2016) (“The FPA leaves no room either for direct state regulation of the \nprices of interstate wholesales or for regulation that would indirectly achieve the same result.” \n(internal quotation marks omitted”). \n40 \nSee id. at 164 (“That Maryland was attempting to encourage construction of new in-state generation \ndoes not save its program. States, of course, may regulate within the domain Congress assigned to \nthem even when their laws incidentally affect areas within FERC’s domain. See Oneok, Inc. v. \nLearjet, Inc., 575 U. S. 373, 385, 135 S. Ct. 1591, 191 L. Ed. 2d 511, 528 (2015) (whether the Natural"},{"page":31,"startToken":10192,"endToken":10540,"text":"- 31 - \nmatching costs of new transmission network upgrades to data centers.41 A similar and \ncomplementary proceeding is needed to match of the costs of new resources to support \nresource adequacy to data centers. \n The Remedial Directive provides terms and conditions for wholesale energy service \nto support resource adequacy, similar, in so far as the Commission’s jurisdiction is \nconcerned, to the Fixed Resource Requirement (“FRR”) alternative that allows for eligible \nLSEs to satisfy PJM’s capacity requirements through a plan consisting of a list of owned or \ncontrolled resources meeting PJM’s criteria.42 Under the RAA’s provisions for FRR \nalternative plans, an LSE takes the responsibility and risk to procure, by contract or \nownership, resources needed to support resource adequacy in the PJM region. PJM’s role is \nlimited to ensuring that resources meet the applicable criteria. Under the Remedial \nDirective, LSEs serving data centers are required to identify data center load, so that PJM \ncan remove it from RPM Auctions, and reviews LSEs’ resources included in its plan to meet \ncapacity obligations related to data centers. The Remedial Directive builds upon the \nvoluntary matching process element of the RBF Proposal (at 30–31), which allows LSEs to \nsatisfy their capacity obligations through resources, procured by contract or ownership, that \nmeet PJM criteria. There is no material difference, in so far as the Commission’s exclusive \njurisdiction over resource adequacy is concerned,43 between the Remedial Directive and the \nexisting FRR alternative rules, and the voluntary matching element of the RBP Filing. PJM’s \nadministration of the RAA and FRR plans approved by FERC since 2006 has never been \n \n \nGas Act (NGA) preempts a particular state law turns on “the target at which the state law \naims”).[citation omitted] But States may not seek to achieve ends, however legitimate, through \nregulatory means that intrude on FERC’s authority over interstate wholesale rates, as Maryland has \ndone here.”); see also Conn. Dep't of Pub. Util. Control v. FERC, 569 F.3d 477, 481 (2009). \n41 \nSee Large Loads Show Cause Order. \n42 \nSee RAA Schedule 8.1. \n43 \nSee Hughes, 578 U.S. 150."},{"page":32,"startToken":10540,"endToken":10782,"text":"- 32 - \nfound outside of FERC’s jurisdiction nor has the issue of jurisdictional basis for the RAA \nand FRR plans been raised on appeal.44 \nThe reason why the RBP Filing should be rejected, and the Remedial Directive \nshould issue instead, is the broadly recognized need to protect reliability and affordability \nin the PJM Region. The RBF Filing fails to address reliability and may lock in \nunaffordability in the PJM Region for 15 years. Meanwhile, contrary to the fundamental \ngoals of the Pledge and Principles, PJM has shifted the costs and risks of the data center \ndevelopers who are driving the extraordinary and immediate need for new resources to \nexisting customers even though the data centers are ready and willing to assume the costs \nand risks they create. The Remedial Directive can fully and timely implement the goals of \nthe Pledge and Principles. \nII. CONCLUSION \nThe Market Monitor respectfully requests that the Commission afford due \nconsideration to this pleading as the Commission resolves the issues raised in this \nproceeding. \n \nJoseph E. Bowring \nIndependent Market Monitor for PJM \nPresident \nMonitoring Analytics, LLC \n2621 Van Buren Avenue, Suite 160 \nEagleville, Pennsylvania 19403 \n(610) 271‐8051 \njoseph.bowring@monitoringanalytics.com \n \nRespectfully submitted, \n \nJeffrey W. Mayes \n \nGeneral Counsel \nMonitoring Analytics, LLC \n2621 Van Buren Avenue, Suite 160 \nEagleville, Pennsylvania 19403 \n(610) 271‐8053 \njeffrey.mayes@monitoringanalytics.com \n \n44 \nSee PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006), order on reh’g, 119 FERC ¶ 61,318 (2007)."},{"page":33,"startToken":10782,"endToken":10906,"text":"- 33 - \nCatherine A. Tyler \nDeputy Market Monitor \nMonitoring Analytics, LLC \n2621 Van Buren Avenue, Suite 160 \nEagleville, Pennsylvania 19403 \n(610) 271‐8050 \ncatherine.tyler@monitoringanalytics.com \nPaul G. Scheidecker \nSenior Analyst \nMonitoring Analytics, LLC \n2621 Van Buren Avenue, Suite 160 \nEagleville, Pennsylvania 19403 \n(610) 271‐8050 \npaul.scheidecker@monitoringanalytics.com \nAlexandra Salaneck \nSenior Analyst \nMonitoring Analytics, LLC \n2621 Van Buren Avenue, Suite 160 \nEagleville, Pennsylvania 19403 \n(610) 271‐8050 \nalexandra.salaneck@monitoringanalytics.com \nJohn Hyatt \nSenior Economist \nMonitoring Analytics, LLC \n2621 Van Buren Avenue, Suite 160 \nEagleville, Pennsylvania 19403 \n(610) 271‐8050 \njohn.hyatt@monitoringanalytics.com \nDevendra R. Canchi \nSenior Analyst \nMonitoring Analytics, LLC \n2621 Van Buren Avenue, Suite 160 \nEagleville, Pennsylvania 19403 \n(610) 271‐8050 \ndevendra.canchi@monitoringanalytics.com \n \nDated: August 21, 2026"},{"page":34,"startToken":10906,"endToken":10911,"text":"ATTACHMENT A \nMarket Monitor Proposal"},{"page":35,"startToken":10911,"endToken":11420,"text":"© Monitoring Analytics 2026 | www.monitoringanalytics.com \nDATE: \nJune 30, 2026, Meeting Date \nTO: \nCIFP: Reliability Backstop \nFROM: \nIMM \nSUBJECT: \nProposed reliability backstop auction design V6 \nThe most important criterion for evaluating proposals to address how to reliably serve new \ndata center load is the assignment of the costs and risks associated with LSEs serving data \ncenter load.1 For example, the failure to exclude new data center load from the BRAs, as PJM \nproposes, would by definition impose significant costs on other customers and therefore violate \nthe basic principle that data center costs should not be imposed on other customers. The rules \nmust protect just and reasonable pricing for capacity that serves existing customers. To date, \nthe capacity costs imposed on existing customers by data centers have been $23 billion.2 As \nanother example, PJM’s proposal assigns the ultimate backstop risk associated with serving \ndata center load to other PJM customers, whether it derives from an expected data center not \nshowing up or the matching new generation not showing up. In contrast, the IMM’s proposal \nstipulates that LSEs require the data centers to enter into 15 year bilateral contracts with new \ngeneration resources that assign costs and risks between the two parties to the bilateral contract. \nThe IMM proposal adds obligations to the RAA that require LSEs serving data center loads to \ndemonstrate that the data centers have entered into bilateral contracts for new capacity that \nmeet defined criteria. This is analogous to the requirements for FRR entities. \nThe preferred option for LSEs serving data centers that add load to the PJM system is for LSEs \nto require, as a term and condition of service for such data centers, that the data centers bring \ntheir own new generation (BYONG).3 For those LSEs serving data centers that do not bring \ntheir own new generation that meets the defined requirements, the IMM proposes that PJM \nrun a reliability backstop auction (RBA) designed to meet all LSEs’ expected data center load \nthat has not entered into a 15 year bilateral contract with new generation. \nThe IMM proposes a specific reliability backstop auction design. The goal is to incorporate \nmarket forces as much as possible and to minimize planning choices by PJM or others. The \n \n1 \nThe Supreme Court has recognized FERC’s jurisdiction to ensure resource adequacy through the \nRAA and auctions conducted under the RAA, and, further, that these federal rules preempt state \nactions interfering with that regulatory construct. See Hughes v. Talen Energy Mktg., LLC, 578 U.S. \n150, 155 (2016) (recognizing FERC’s and RTO’s authority, including through capacity market \nauctions, to “ensure the availability of an adequate supply of power at some point in the future.”). \n2 \nSee the “Analysis of the 2027/2028 RPM Base Residual Auction – Part A,” (January 5, 2026) \n. \n3 \nThe MW of new generation to meet data center load is in UCAP terms and includes reserves based \non the system target reserve margin."},{"page":36,"startToken":11420,"endToken":11923,"text":"© Monitoring Analytics 2026 | www.monitoringanalytics.com \n2 \nproposed IMM design does not impose data center costs or risks on LSEs or EDCs or PJM or \nother customers, consistent with the Principles defined by the National Energy Dominance \nCouncil and the PJM Governors and the Pledge by defined hyperscalers.4 \nThe IMM design creates a dedicated mechanism for LSEs serving new large data center load \ndesigned to complement, not replace, PJM’s existing RPM construct. It is intended to ensure \nlong term resource adequacy for data center load by directly linking LSEs’ service to new data \ncenter load with dedicated new generation, creating transparent investment signals based on a \n15 year contract term. \nOnly organic load and existing data center load as of June 1, 2026, would be included in the \n2028/2029 BRA and in the 2029/2030 BRA. The maximum price for these BRAs would be based \non the IMM’s CT net CONE calculations from the most recent quadrennial review, updated to \nreflect current market conditions as necessary.5 There would be no floor price. All forecast data \ncenter load would be removed from the 2028/2029 BRA and from the 2029/2030 BRA. All LSEs \nserving data center load that was not online on June 1, 2026, would be required to commit to \nrequiring that data center loads have contracts that meet the requirements of the BYONG \noption, or to participating in the reliability backstop auction. LSEs serving data center load \nwould have the option to commit to requiring a specific future BYONG plan that meets the \nnecessary terms and conditions and not be included in the auction. If a data center load does \nnot meet the requirement to bring new generation, the data center load would be subject to the \ncurtailment alternative. If data center load takes the BYONG option, the IMM’s proposal is that \nthe bilateral BYONG contracts be required to have the same basic characteristics as the bilateral \ncontracts resulting from the reliability backstop auction, e.g. a 15 year term, must offer \nobligation in the capacity market at zero price, must offer obligation in the energy market at \ncost-based offers, location in the same child LDA, and matching energy output duration with \nload duration on an hourly basis. All capacity resources would be treated as capacity resources \nunder the PJM Tariff rules. \nThe IMM’s design for the reliability backstop auction is to run a full single clearing price auction \nusing the BRA capacity market clearing model for data center load. LSEs would require data \ncenters to participate in the reliability backstop auction if they do not have a bilateral contract \n \n4 \nSee National Energy Dominance Council, Statement of Principles Regarding PJM (January 16, 2026) \n; see also White House, \n“Ratepayer \nProtection \nPledge \nProclamation,” \n(March \n4, \n2026) \n. \n5 \nSee PJM. Markets and Reliability Committee, Quadrennial Review Issues < https://www.pjm.com/-\n/media/DotCom/committees-groups/committees/mrc/2025/20250925/20250925-item-05b---\nquadrennial-review-imm-proposal---presentation.pdf> (September 25, 2025)."},{"page":37,"startToken":11923,"endToken":12452,"text":"© Monitoring Analytics 2026 | www.monitoringanalytics.com \n3 \nfor new generation that meets the requirements of such contracts. This reliability backstop \nauction would be run soon after the 2028/2029 BRA. Such an auction design could be repeated \nin the future as needed to address additional new data center load that is not included in the \nfirst reliability backstop auction but would not be required and would not be run on a \npredefined schedule. The reliability backstop auction would include the location and MW of \neach data center that participates, the location and MW of proposed generation that \nparticipates, full PJM CETO/CETL parameters net of the impacts from the applicable BRA, and \nany resultant locational price separation. The only product offered would be 15 year generation \ncapacity at a maximum offer price equal to the nominal levelized equivalent of the IMM’s \ncalculated combustion turbine Gross CONE provided in the latest quadrennial review, \nupdated to reflect current market conditions as necessary, net of defined energy and ancillary \nservice net revenues in each year of the contract. That equivalent, in $/MW-day, would be \nhigher than the calculated net CONE in year one because the product is based on a 15 year \nlevelized gross CONE while the current cap is based on a 20 year levelized gross CONE net of \nnet revenues for year one. \nThe reliability backstop auction would result in cleared generation capacity by LDA. If offers \nare less than demand, the demand offers would clear in order from highest to lowest. If demand \nis less than offers, the supply offers would clear in order from lowest to highest. After the \nauction, a matching algorithm would be used to match individual cleared generation resources \nwith individual data centers subject to locational constraints such that the number of bilateral \ncontracts are minimized. \nIn order to meet the intended incentive goal, the total payments received for new generation \nshould equal Gross CONE, including both net revenue from the energy and ancillary services \nmarkets and capacity payments. The net revenues would be explicitly incorporated. The actual \nannual payments under the contracts would include the defined energy and ancillary service \nnet revenues calculated annually for each year and the remaining net CONE not covered by \nthe net revenues. The contracts would be for total payments including energy and ancillary \nservices net revenues and the remaining net cost of capacity. The energy and ancillary services \nrevenues could be calculated annually on a forward looking basis or on an historical basis. A \nsingle method should be selected that applies to all contracts. \nIn the reliability backstop auction, the demand for generation capacity would be equal to the \nspecific demand for 15 year capacity from individual data centers, plus the required reserve \nmargin, for each data center, to ensure reliability. There is no forecast of demand, by EDCs or \nby PJM. All data centers with expected demand greater than or equal to 5.0 MW would be \nincluded in the auction. A goal of the defined size is to prevent artificial segmentation of data \ncenter load to circumvent the size threshold. The maximum price for the demand bids would \nequal the maximum offer price for new generation."},{"page":38,"startToken":12452,"endToken":12984,"text":"© Monitoring Analytics 2026 | www.monitoringanalytics.com \n4 \nSellers in the reliability backstop auction would be new generation only, with clearly defined \neligibility. New generation would not include uprates to existing generation, uncleared \ncapacity, repowered capacity, units that retired after June 1, 2025, demand side resources or \nrelicensing. This definition ensures that all cleared capacity represents investment in new \nphysical supply rather than redefining existing resources. The goal is to support new \ngeneration and to prevent gaming of the rules by reclassifying existing capacity resources as \nnew. The new generation must be located within the same child LDA as the data center to help \nensure long term deliverability to that load over the 15 year life of the contract. The output of \nthe new generation must reasonably match the hour by hour load profile of the data center. \n(This is not capacity factor matching.) For example, a standalone solar resource would not \nqualify but a combined solar and battery resource could qualify. The energy output of the new \ngeneration must equal or exceed the data center load whenever the new generation is available, \nsubject to locational constraints. \nGeneration selected in the reliability backstop auction would be required to comply with all \nrequirements of the PJM capacity market. For example, new generation capacity is required to \nhave CIRs and to be deliverable and has an RPM must offer obligation. All of this generation \nwould also be required to have the same obligations in the energy market as committed \ngeneration capacity resources, including an energy market must offer obligation. \nWhen the clearing process is complete and each generation offer is associated with one or more \nidentified data center loads, the LSEs would require that generators and data center loads enter \ninto 15 year bilateral contracts that do not permit any cost or risk shifting to other customers. \nThe contracts would be based on a tariff defined standard contract. The risks associated with \nthe load changing or withdrawing and generation changing or failing would be fully addressed \nin the bilateral contracts. New generation capacity resources clearing in the reliability backstop \nauction would have an initial capacity accreditation based on the recent EFORd performance \nof comparable generation and would, after two years of operation, have unit specific ELCC \nvalues based on actual unit performance and therefore subject to management by the generator. \nThe risks associated with changes in capacity accreditation values would be fully addressed in \nthe bilateral contracts. \nWhen the bilateral contracts are final, including bilateral contracts reached under the BYONG \noption, the data center load plus the reserve margin has an RPM must buy obligation and the \ncorresponding generation capacity has an RPM must offer obligation, after the capacity \ncommercial operation date, in future BRAs as price takers for the 15 year contract term. A \ncontract for differences would ensure that the load pays and the generation receives the \ncontract price in the financial settlement. \nThe IMM’s proposal addresses any potential state/federal jurisdictional issues. LSEs would be \nrequired, as a condition of service, in the RAA, to show that each data center that they serve \nhas a bilateral contract(s) in place with a source of generation for at least 15 years that meets"},{"page":39,"startToken":12984,"endToken":13179,"text":"© Monitoring Analytics 2026 | www.monitoringanalytics.com \n5 \nthe identified requirements of such contracts. The bilateral contracts would address all pricing \nand risk issues solely between the parties to the contract with no recourse to other customers. \nUnder the IMM proposal, the qualifying bilateral contracts assign all risks to the bilateral \ncounterparties and no risks are assignable to EDCs, LSEs, PJM or any other customers. The \nLSEs must ensure that the data centers meet the requirement to have a bilateral contract based \non the requirements of the RAA, but the LSEs are not counterparties to the capacity supply \ncontract. LSEs that do not maintain their obligations under the RAA will face consequences \ndefined in the RAA.6 The data center and the generation capacity seller are the counterparties \nto the capacity supply contracts. PJM and other PJM participants provide no credit support of \nany kind for the contracts. There is no recourse to PJM or its members. Credit issues are entirely \nbetween the parties to the bilateral contracts. \n \n \n6 \nSee RAA § 5.2, referencing OA § 15.1. The RAA can be amended only by action of the PJM Board \nand FERC approval, per RAA § 16.4."},{"page":40,"startToken":13179,"endToken":13184,"text":"- 0 - \n \n \n \n \n \nATTACHMENT B \nTechnical Appendix"},{"page":41,"startToken":13184,"endToken":13386,"text":"- 1 - \nA. Issues with PJM’s maximum price \nTable 2 shows PJM CT Gross and Net CONE, including the PJM Net CONE value \nbased on August 2025 forwards and an estimated Net CONE value based on August 2026 \nforwards \nTable 2 PJM CT Gross and Net CONE \n \n \n \n \nPJM CT Gross & Net CONE ($/MW-Day)\nEMAAC\nSWMAA\nC Rest of RTO\nWMAAC\nCOMED\nRTO\nGross CONE (ICAP)\n$596\n$608\n$590\n$592\n$679\n$613\nForward E&AS (67th percentile)\n$159\n$343\n$394\n$320\n$214\n$361\nNet CONE (ICAP)\n$438\n$265\n$195\n$271\n$465\n$228\nGross CONE (UCAP)\n$754\n$769\n$747\n$749\n$860\n$776\nNet CONE (UCAP)\n$554\n$336\n$247\n$343\n$589\n$325\nVRR Curve (UCAP)\na1) 1.15 x Gross CONE - 0.75 x Net E&AS\n$718\n$560\n$483\n$557\n$785\n$555\na2) 0.2 x Gross CONE\n$151\n$154\n$149\n$150\n$172\n$155\nPoint A (99% of RR, max of a1,a2)\n$718\n$560\n$483\n$557\n$785\n$555\nPoint B (101.5% of RR, 0.5 x Point A)\n$359\n$280\n$242\n$278\n$393\n$278\nPoint C (106.0% of RR, $0)\n$0\n$0\n$0\n$0\n$0\n$0\na1) 1.15 x Gross CONE - 0.75 x Net E&AS (EAS 24% higher)\n$473"},{"page":42,"startToken":13386,"endToken":13452,"text":"- 2 - \n \nCERTIFICATE OF SERVICE \nI hereby certify that I have this day served the foregoing document upon each \nperson designated on the official service list compiled by the Secretary in this proceeding. \nDated at Eagleville, Pennsylvania, \nthis 21st day of August, 2026. \n \nJeffrey W. Mayes \nGeneral Counsel \nMonitoring Analytics, LLC \n2621 Van Buren Avenue, Suite 160 \nEagleville, Pennsylvania 19403 \n(610)271‐8053 \njeffrey.mayes@monitoringanalytics.com"}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":5,"endAt":461,"startToken":0,"endToken":1574},{"p":5,"at":461,"title":"I. PROTEST","method":"PDF bookmark","endPage":5,"endAt":473,"startToken":1574,"endToken":1576},{"p":5,"at":473,"title":"A. The RBP Filing Has Not Been Shown Just and Reasonable.","method":"PDF bookmark","endPage":7,"endAt":1553,"startToken":1576,"endToken":2402},{"p":7,"at":1553,"title":"B. The RBP Filing Is Deficient, Unjust and Unreasonable.","method":"PDF bookmark","endPage":7,"endAt":1611,"startToken":2402,"endToken":2411},{"p":7,"at":1611,"title":"1. The PJM RBP Filing would violate fundamental elements of the PJM capacity market design.","method":"PDF bookmark","endPage":8,"endAt":144,"startToken":2411,"endToken":2478},{"p":8,"at":144,"title":"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.","method":"PDF bookmark","endPage":9,"endAt":7,"startToken":2478,"endToken":2720},{"p":9,"at":7,"title":"3. PJM’s RBP Filing would inappropriately require LSEs to bear costs and risks.","method":"PDF bookmark","endPage":10,"endAt":1390,"startToken":2720,"endToken":3278},{"p":10,"at":1390,"title":"4. The RBP Filing is inconsistent with the basic locational design of the PJM Capacity Market.","method":"PDF bookmark","endPage":10,"endAt":1948,"startToken":3278,"endToken":3368},{"p":10,"at":1948,"title":"Attachment A - Revisions to the PJM Open Access Transmission Tariff and PJM Reliability","method":"printed heading","endPage":11,"endAt":1610,"startToken":3368,"endToken":3648},{"p":11,"at":1610,"title":"5. The RBP Filing abandons single clearing price auction in favor of pay as bid.","method":"PDF bookmark","endPage":13,"endAt":533,"startToken":3648,"endToken":4179},{"p":13,"at":533,"title":"6. The PJM RBP Filing fails to address market power.","method":"PDF bookmark","endPage":14,"endAt":8,"startToken":4179,"endToken":4404},{"p":14,"at":8,"title":"7. The RBP Filing shifts ELCC risk from generators to customers. The RBP filing shifts the risks of generators failing to perform to customers.","method":"PDF bookmark","endPage":14,"endAt":1565,"startToken":4404,"endToken":4657},{"p":14,"at":1565,"title":"Attachment A – Marked Tariff Records at Attachment DD, 18.5(e)(i).","method":"printed heading","endPage":15,"endAt":301,"startToken":4657,"endToken":4814},{"p":15,"at":301,"title":"8. The RBP Filing is inconsistent with the capacity market approach to penalties for performance.","method":"PDF bookmark","endPage":18,"endAt":8,"startToken":4814,"endToken":5705},{"p":18,"at":8,"title":"1. PJM proposes to include all large loads rather than just data center load.","method":"PDF bookmark","endPage":18,"endAt":1335,"startToken":5705,"endToken":5908},{"p":18,"at":1335,"title":"2. The RBP Filing fails to match supply and demand for energy","method":"PDF bookmark","endPage":19,"endAt":378,"startToken":5908,"endToken":6156},{"p":19,"at":378,"title":"3. The RBP Filing is inconsistent with the requirement to provide revenue certainty to new generation for 15 years.","method":"PDF bookmark","endPage":19,"endAt":964,"startToken":6156,"endToken":6248},{"p":19,"at":964,"title":"4. The RBP Filing includes inconsistent definitions of the capacity that can satisfy the requirements to meet the data center load.","method":"PDF bookmark","endPage":22,"endAt":73,"startToken":6248,"endToken":6938},{"p":22,"at":73,"title":"5. DR as capacity to meet demand of data centers","method":"PDF bookmark","endPage":24,"endAt":1914,"startToken":6938,"endToken":8035},{"p":24,"at":1914,"title":"6. The proposed RBP process is not consistent with the cost minimizing principles used for clearing energy and capacity markets in PJM today.","method":"PDF bookmark","endPage":25,"endAt":1562,"startToken":8035,"endToken":8373},{"p":25,"at":1562,"title":"Attachment A - Revisions to the PJM Open Access Transmission Tariff and PJM Reliability","method":"printed heading","endPage":27,"endAt":99,"startToken":8373,"endToken":8844},{"p":27,"at":99,"title":"7. PJM failed to update the maximum price calculation","method":"PDF bookmark","endPage":28,"endAt":435,"startToken":8844,"endToken":9245},{"p":28,"at":435,"title":"C. Rejecting the RBP Filing Would Allow the Commission to Direct and Appropriate Remedy.","method":"PDF bookmark","endPage":28,"endAt":526,"startToken":9245,"endToken":9259},{"p":28,"at":526,"title":"1. The Current Rules Are Inadequate to Address Prevailing Market Conditions.","method":"PDF bookmark","endPage":28,"endAt":784,"startToken":9259,"endToken":9298},{"p":28,"at":784,"title":"2. The Record Provides Sufficient Information for the Commission to Immediately Issue a Remedial Directive that Protects Reliability and Affordability.","method":"PDF bookmark","endPage":32,"endAt":870,"startToken":9298,"endToken":10682},{"p":32,"at":870,"title":"II. CONCLUSION","method":"PDF bookmark","endPage":34,"endAt":0,"startToken":10682,"endToken":10906},{"p":34,"at":0,"title":"ATTACHMENT A","method":"printed heading","endPage":40,"endAt":17,"startToken":10906,"endToken":13180},{"p":40,"at":17,"title":"ATTACHMENT B","method":"printed heading","endPage":41,"endAt":7,"startToken":13180,"endToken":13185},{"p":41,"at":7,"title":"A. Issues with PJM’s maximum price","method":"PDF bookmark","endPage":42,"endAt":9,"startToken":13185,"endToken":13387},{"p":42,"at":9,"title":"CERTIFICATE OF SERVICE","method":"printed heading","endPage":42,"endAt":456,"startToken":13387,"endToken":13452}]}