{"document":{"slug":"filing-er26-3380-pjm-original-attachment-3","title":"Attachment C - Croop Affidavit.pdf","issued":"2026-07-31","accession":"20260731-5214","docket":"ER26-3380-000","group":"PJM filings","filer":"PJM Interconnection, L.L.C.","kind":"attachment","file":"sources/originals/20260731-5214_04.pdf","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_Number=20260731-5214","parent":"filing-er26-3380-pjm-original","text_file":"20260731-5214_04.txt","sha256":"912dbc5b83b638428ec9ee76eb873c70514a5df128c66b6df374c71a92be9da3","pages":26,"tokens":7950,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":20,"text":"Attachment C \n \n \n \n \n \n \n \nAffidavit of Ms. Danielle Croop, \nSenior Manager in the Market Design group of \nPJM Interconnection, L.L.C."},{"page":2,"startToken":20,"endToken":355,"text":"UNITED STATES OF AMERICA \nBEFORE THE \nFEDERAL ENERGY REGULATORY COMMISSION \n \n \n \n \n \n \n \n) \nPJM Interconnection, L.L.C. \n \n) \n \nDocket No. ER26-____-000 \n \n \n \n \n \n \n) \n \nAFFIDAVIT OF DANIELLE CROOP \nON BEHALF OF PJM INTERCONNECTION, L.L.C. \n1. \nMy name is Danielle Croop, Senior Manager in the Market Design group for PJM \nInterconnection, L.L.C. (“PJM”).  My business address is 2750 Monroe Blvd., \nAudubon, Pennsylvania, 19403.  I am submitting this affidavit on behalf of PJM to \nsupport the proposed reforms to PJM’s Open Access Transmission Tariff (“Tariff”) \nand PJM’s Reliability Assurance Agreement Among Load Serving Entities \n(“RAA”) to implement the Reliability Backstop Procurement (“RBP”) framework \nby providing support for PJM’s proposal to: \na. Establish a region-wide procurement target for the RBP; \nb. Require that supply meet certain criteria to be eligible to reduce the Initial \nRBP Target, which differs from the criteria for supply eligible to be RBP \nResources;  \nc. Require that supply meet certain criteria to be eligible to submit RBP Sell \nOffers as RBP Resources, which differs from the criteria for supply eligible \nto reduce the Initial RBP Target;   \nd. Rely on a pay-as-bid clearing structure based on a MW-weighted average \nof the levelized procurement cost cap equal to $555/megawatt (“MW”)-day \nUnforced Capacity (“UCAP”); \ne. Select resources based on a MW-weighted average of the levelized \nprocurement cost;   \nf. Not propose explicit market power screening or mitigation measures as part \nof the RBP; \ng. Settle RBP Resource commitments based on contract for difference \n(“CfD”) Structure; and \nh. Proposed Cost Allocation Methodology. \nIn addition, I am sponsoring one exhibit, appended to my affidavit as Exhibit 1 and \nentitled RBP Selection Process Examples.  Exhibit 1 contains three simplified \nexamples that help demonstrate how the RBP selection process works.   \nQUALIFICATIONS \n2. \nIn my role as Senior Manager for PJM, I lead a team of Market Design Specialists \nand Economists on the development of PJM’s market design across all of PJM’s \nmarkets including the energy, ancillary services, and capacity markets.  My \nresponsibilities include leading the development of wholesale market rules and"},{"page":3,"startToken":355,"endToken":845,"text":"2 \nparticipation frameworks that advance market efficiency and grid reliability.  I \njoined PJM in 2014 as an Engineer, and since then, I have held numerous other \nroles, including as a Senior Engineer, Senior Lead Engineer, Senior Lead Market \nDesign Specialist, and Market Design Manager, providing technical support and \nleading cross-divisional teams on market design, market evolution initiatives \nrelated to energy storage and distributed energy technologies participating in the \nPJM markets, and balancing operations at PJM, including involvement in a number \nof North American Electric Reliability Corporation subcommittees and initiatives.   \n3. \nPrior to joining PJM, I was employed by the SI Organization, Inc. as a System \nEngineer supporting large system integrations.  I received a Bachelor of \nEngineering Degree and a Master of Engineering (Electrical Engineering) from \nDrexel University in Philadelphia, Pennsylvania, and have obtained a Certificate in \nEngineering Management. \nI. \nKEY DESIGN CONSIDERATIONS AND RATIONALE \n4. \nPJM is aiming to commence a procurement of new capacity resources through the \nRBP1 on September 30, 2026.  PJM will set a procurement target for the RBP, \ncalculated as the shortfall MW from the 2028/2029 Base Residual Auction \n(“BRA”), as adjusted to reflect voluntarily contracted new capacity procured by \nload coming on the PJM system in the 2027/2028 and 2028/2029 Delivery Years \nand any supported load that opts-out of the procurement.  The shortfall MW from \nthe 2028/2029 BRA was 6,831.3 MW of UCAP below the Regional Transmission \nOrganization (“RTO”) Reliability Requirement. \n5. \nThe RBP will function as a safety net to address the shortfall MW from the \n2028/2029 BRA that has not been addressed by new load bringing their own new \ncapacity through bilateral agreements or otherwise.  The RBP is a stop-gap, one-\ntime measure aimed specifically at addressing the resource adequacy shortfall in \nthe PJM Region, an effort design to work in part with the load that has voluntarily \nbrought supply to the PJM Region—independently or with support of ongoing PJM \nbilateral matching efforts—and a return to market fundamentals to support the \nexpected load growth over the next decade.  The RBP seeks to obtain “RBP \nResources,” a new, defined term in the Tariff, for a fixed, 15-year period, which \nwill be set from the 2028/2029 Delivery Year to the 2042/2043 Delivery Year.  The \ncommitment term of the RBP Resources will vary by each resource’s commercial \noperation date.  Those RBP Resources with a commercial operation date later than \n2028/2029 will have a shorter commitment, and the RBP commitments will not \nextend beyond the 2042/2043 Delivery Year.  \n6. \nPJM will run the procurement mechanism as a pay-as-bid, capacity-only structure, \nwith a MW-weighted average levelized procurement cost maximum willingness to \npay equal to $555/MW-day UCAP across all Delivery Years.  PJM will commit \n \n1 All capitalized terms that are not otherwise defined herein have the meaning defined in the Tariff, Amended \nand Restated Operating Agreement of PJM Interconnection, L.L.C., or the RAA."},{"page":4,"startToken":845,"endToken":1264,"text":"3 \nresources at an RTO-level.  The total costs of the daily RBP Charges will be \nallocated to Load Serving Entities (“LSE”) within a zone/area that had forecasted \nload growth, based on an RBP Obligation (“RBO”) MW, which is a newly defined \nterm that incorporates state-determined allocations of RBP UCAP MW to LSEs \nand end-use customers, where available, that I elaborate on further, below. \nII. \nREGION-WIDE PROCUREMENT OF RBP RESOURCES \n7. \nThe RBP is being driven by the resource adequacy shortfall at the RTO level.  \nTherefore, the RBP aims to pool the supply and demand at the RTO level to address \nthis shortfall.  PJM does not propose to match specific supply to specific demand \nor to apply locational constraints in the central procurement.  \n8. \nPJM recognizes there are locational considerations at large for resource adequacy, \nand these constraints are modeled in the Reliability Pricing Model (“RPM”).  RPM \nis an annual three-year forward framework, which allows PJM to model the \nnecessary locational parameters—Capacity Emergency Transfer Objectives \n(“CETO”) and Capacity Emergency Transfer Limits (“CETL”)—to accurately \ncapture the locational needs in the capacity market.  By contrast, PJM does not \nproject and calculate these parameters 15-years out, which is the eligible term of \nthe RBP, because PJM does not have the information needed to determine such \nlocational parameters for 15-year term capacity commitments.  \n9. \nPJM’s interconnection process ensures the initial deliverability of new capacity to \nthe RTO.  Going forward, the PJM Regional Transmission Expansion Plan \n(“RTEP”) process annually studies and addresses any transmission upgrades \nneeded to ensure the ongoing deliverability of capacity resources.  Load \ndeliverability is also assessed as part of the RTEP process, which will identify \ntransmission needs as load patterns change. \nIII. \nINTENTIONALLY \nDIFFERENT \nREQUIREMENTS \nFOR \nSUPPLY \nELIGIBLE TO REDUCE THE INITIAL RBP TARGET AND SUPPLY \nELIGIBLE TO SUBMIT RBP SELL OFFERS AS RBP RESOURCES   \n10. \nPJM is proposing to reduce the Initial RBP Target MW by Qualifying RBP Offset \nUCAP MW, which is a new, defined term that represents net new capacity that \nmeets certain qualifications.  Importantly, the requirements to be Qualifying RBP \nOffset UCAP MW that may decrement the Initial RBP Target MW are different, \nand more inclusive than the requirements to qualify as RBP Resources with RBP \nUCAP MW that may submit sell offers in the RBP.   \n11. \nThe capacity provided by Qualifying RBP Offset UCAP MW and by RBP \nResources that may sell RBP UCAP MW in the RBP have different obligations and \ntherefore, PJM is proposing different criteria for these two categories of capacity."},{"page":5,"startToken":1264,"endToken":1652,"text":"4 \nA. \nSupply Eligible to Reduce Initial RBP Target \n12. \nFor supply to qualify as Qualifying RBP Offset UCAP MW, counterparties would \nbe required to demonstrate the existence of commercial bilateral agreements or self-\nsupply and show that the associated resources result in net new UCAP being made \navailable to the PJM system.  The following is a list of resources that could \ndemonstrate net- new UCAP and would be considered in this case: \na. New build including new resources that obtain Capacity Interconnection \nRights (“CIR”) transferred from deactivated resources or resources that \nhave announced deactivation as of April 10, 2026; \nb. Uprates (incremental Installed Capacity (“ICAP”)/CIR only); \nc. Repowering of deactivated generators that have retired as of April 10, 2026; \nd. Surplus interconnection (incremental only); \ne. Resources that undergo fuel-switching to another more efficient fuel type \nthat results in a higher UCAP and CIR uprate (incremental only); and \nf. New Load Management (Emergency or Pre-emergency Demand Resources \nand Distributed Energy Resource (“DER”)) Capacity Aggregation \nResources.  \n13. \nPJM is defining this criterion broadly to capture all meaningful sources of new \nUCAP serving new load that contribute to resource adequacy and prevent double \nprocuring for new load that is bringing new capacity to the system. \nB. \nSupply Eligible to Participate as RBP Resources in the RBP \n14. \nResources eligible to participate as RBP Resources in the RBP, if accepted, will be \nprocured up through the end of a fixed, 15-year capacity commitment.  PJM \nbelieves additional requirements are necessary to ensure that resources permitted \nto participate in the RBP align with the underlying objectives of the procurement \nto obtain new physical capacity for the system and demonstrate a high likelihood \nof successfully entering service and remaining available throughout the \ncommitment period. \n15. \nThe RBP Resource eligibility criteria are comparatively more restrictive than the \ncriteria for Qualifying RBP Offset UCAP MW, and specifically in addition to \nrequiring new UCAP be brought to the system, there is a requirement that there is \nnew ICAP and Maximum Facility Output (“MFO”) being brought to the system, \nand new or transferred CIRs.2  These additional requirements remove the eligibility \nof two defined sources of new UCAP that may be Qualifying New UCAP MW and \n \n2 CIRs can be transferred from a deactivated resource or a resource that has announced deactivation as of \nApril 10, 2026."},{"page":6,"startToken":1652,"endToken":2127,"text":"5 \neligible to reduce the Initial RBP Target.  More specifically, the following are not \neligible to serve as RBP Resources:  \na. Surplus interconnection (incremental only); and \nb. Resources that undergo fuel-switching to another more efficient fuel type \nthat results in a higher UCAP or CIR uprate (incremental only). \n16. \nThese more restrictive eligibility requirements are intended to ensure that resources \nreceiving long-term commitments are capable of delivering the reliability benefits \nthat the RBP is designed to secure, reduce risk, and improve confidence in project \nexecution.   \n17. \nThe exclusion of Surplus Interconnection Service (“SIS”) resources from supply \neligible to serve as RBP Resources was driven by the fact that these projects do not \nbring any additional MFO or CIRs to the system.  This is a defined requirement for \nresources entering through the SIS-defined Tariff provisions.  Resources that do \ninterconnect and operate under SIS do not have any rights on their own to the PJM \nsystem.  By design, a surplus resource can only operate while the existing resource \nis in service, or no more than one year after the deactivation of the existing resource, \nand when the existing resource is not operating and using the interconnection \nservice.  Given the 15-year term, resources need to be able to operate independently \nto provide certainty of deliverability for a 15-year term.  Further, these projects, \nwhile increasing UCAP in a hybrid configuration, do not have clear contributions \nof UCAP between the existing resource and surplus resource creating uncertainty \nand the need for sensitivities or estimates in both the increase system capacity and \nthe RBP settlements. \n18. \nThis is not a complete barrier to participation of surplus resources in RBP.  As \nmentioned above, these resources are able to participate as Qualifying New UCAP \nMW to reduce the Initial RBP Target.  Further, these sited projects would still have \nan opportunity to offer into the RBP and co-locate with the existing resource and \nbe studied by PJM for increased CIRs and MFO at the facility through the \ninterconnection process.  \n19. \nThe exclusion of resources that undergo fuel-switching to another more efficient \nfuel type that results in a higher UCAP and CIR uprate (incremental only) is also \nnecessary to provide the certainty of deliverability for a 15-year term expected from \nan RBP Resource.  Fuel switching does not bring new ICAP or new MFO on to the \nsystem.  There is an anticipated UCAP increase resulting in the resource Effective \nLoad Carrying Capability (“ELCC”) class change and resulting accreditation, \nhowever the potential new UCAP captured from this resource would require some \nestimate of the incremental UCAP value, which may require sensitivity analyses, \nto determine the delivered incremental UCAP and RBP payment, that cannot be \nbased on any direct increase in ICAP for the resource.  This creates uncertainty in \nwhat capacity will be available to the system in the 15-year term and should be \nsettled under the RBP."},{"page":7,"startToken":2127,"endToken":2571,"text":"6 \n20. \nAdditionally, PJM has proposed more stringent requirements on Demand \nResources and DER Aggregation Resources eligible to qualify as RBP Resources \nrelative to the requirements on such resources for purposes Qualifying RBP Offset \nUCAP MW.  Specifically, to qualify as RBP Resources, Demand Resources and \nDER Aggregation Resources need to have contracts for the RBP term (i.e., up to \n15 years) with the identified sites that are offering as RBP Resources.  This is to \nprovide assurance that the supply will be available for the 15-year term and manage \nthe risk of the supply being available for the full term that PJM is procuring on \nbehalf of load in the RBP.  By contrast, Qualifying RBP Offset UCAP MW does \nnot require 15-year contracts because the commitment terms (length, price, etc.) are \nbeing managed by the commercial contract between the buyer and seller. \nIV. \nPAY-AS-BID STRUCTURE \n21. \nPJM generally supports a single-clearing-price market design and continues to view \nuniform clearing prices as the most efficient market outcome.  Uniform pricing \npromotes transparent price discovery, facilitates forward pricing, and supports \ncompetitive market outcomes and the PJM Region sees the benefits of that design \nacross its existing markets. \n22. \nHowever, the proposed RBP differs significantly from PJM’s standard market \nconstructs and warrants a different settlement approach which is why PJM is \nproposing a pay-as-bid structure for several reasons unique to this procurement. \n23. \nFirst, the RBP is intended as a one-time procurement mechanism designed to \naddress near-term resource adequacy challenges while PJM continues to focus on \nlong-term market fundamentals and supporting continued commercial bilateral \ncontracting.  Because this procurement is not designed to be a durable or repeatable \nprocurement, its pricing outcomes are less likely to serve as incentive market \nsignals. \n24. \nSecond, much of the longer-term capacity that the RBP framework seeks to secure \nis expected to be obtained through bilateral arrangements outside of PJM’s \norganized markets.  A pay-as-bid structure more closely aligns with the economics \nand settlement structures of bilateral contracts and reduces the likelihood that RBP \noutcomes will distort or influence those private contracting activities.   \n25. \nFinally, the proposed procurement is not acquiring a uniform commodity.  \nAlthough the RBP will seek a fixed, 15-year period of time for procurement and \ncost allocation of RBP Resources, those resources may differ based on contract \nduration (dependent on the projected in-service date of selected resources), \ncommercial operation dates, and other factors such as differences in ELCC \naccreditation and varying UCAP across the full term of the commitment.  These \ndifferences create distinct products rather than a single homogeneous offering.  \nEstablishing a uniform clearing price across such varied products would require \nPJM to normalize offers through potentially complex and subjective assumptions."},{"page":8,"startToken":2571,"endToken":3040,"text":"7 \nA pay-as-bid structure avoids those challenges while providing a straightforward \nand transparent procurement framework. \nV.  \nVOLUME-WEIGHTED \nLEVELIZED \nCOST \nPROCUREMENT \nMAXIMUM WILLINGNESS TO PAY OF $555/MW-DAY UCAP \n26. \nPJM believes it is necessary to identify, for the RBP, a maximum willingness to \npay because it is not reasonable to assume that load should be obligated to pay an \nunlimited amount for supply.  As with other PJM procurement mechanisms, an \nupper bound helps balance reliability needs with customer cost protections. \n27. \nIn this procurement, PJM is not receiving direct buy bids or an explicit expression \nof loads’ maximum willingness to pay, and thus PJM is proposing an administrative \nmaximum willingness to pay that PJM believes will appropriately balance \nreliability needs and customer cost protections. \n28. \nThe RPM relies on the Variable Resource Requirement (“VRR”) curve, which is \nderived from the Cost of New Entry, to establish the value PJM is willing to pay \nfor resource commitments in a given Delivery Year.  Specifically, for the \n2028/2029 Delivery Year BRA, absent the temporary price collar, Point 1 on the \nVRR curve is $555MW-day UCAP.  Because the RBP is intended to address a \nspecific resource shortfall identified in the 2028/2029 BRA, PJM is proposing to \nuse Point 1 of the applicable BRA VRR curve as the basis for establishing the \nprocurement maximum willingness to pay for the RBP.  \n29. \nPJM is proposing an RBP maximum willingness to pay to be a MW-weighted \naverage of the levelized procurement cost of all selected RBP Sell Offers to be set \nat $555/MW-day across all Delivery Years.  This results in the cost to load being \nallocated for RBP Charges to not exceed $555/MW-day, on average, over the 15-\nyear term.  Using this average/budget approach to the maximum willingness to pay \n(in comparison to providing a price cap in each Delivery Year or a direct price cap \non offers) allows more flexibility in supply sell offers, to the extent that a \n$555/MW-day maximum willingness to pay may not capture every resource’s costs \nand eliminates a potential barrier to supply participation.  \nVI. \nSELECTION PROCESS \n30. \nPJM is proposing to calculate a levelized procurement cost for each RBP Sell Offer \nto determine the selection.  The levelized cost of capacity is an industry standard \nevaluation metric used in competitive resource procurements across the country.  \nThe levelized cost calculation for evaluation addresses the fundamental issue of a \nsimple MW-weighted average cost by accounting for the time value of money, \nwhich is critical when evaluating contracts spanning 15-year terms, as PJM is \nproposing in the RBP.  Levelizing properly discounts future cost streams to a \ncommon basis, giving us a true economic comparison across bids.  In Exhibit 1, \nappended to my affidavit, I provide examples, with step-by-step explanations, \nwhich illustrate how PJM’s proposed selection process will work."},{"page":9,"startToken":3040,"endToken":3452,"text":"8 \n31. \nThe calculation PJM will use is:  Levelized Cost ($/MW-day) = Net Present Value \n(RBP Sell Offer price * UCAP offered)/Net Present Value (UCAP offered), with a \ndiscount rate equal to 9.5% after-tax average weighted average cost of capital \n(“ATWACC”).  The proposed discount rate is The Brattle Group-estimate \ncalculated value used in the 2025 Periodic Review of VRR Curve Shape and Key \nParameters.3  The purpose of discounting is not to forecast inflation or market \nprices, but to reflect the time value of money and the opportunity cost of invested \ncapital.  The levelized cost is intended to represent the cost per UCAP unit needed \nto recover investment and operating costs over the offer term, and the ATWACC \nrepresents the economically appropriate discount rate.  ATWACC represents the \nminimum expected return required by debt and equity holders and is therefore the \nstandard rate used to annualize long-lived infrastructure costs.  \nVII. \nMARKET MITIGATION \n32. \nPJM is not proposing market power screening or mitigation measures as part of the \nRBP.  The RBP is designed as a pay-as-bid procurement in which each selected \nresource is compensated based on its individual offer rather than a market-clearing \nprice established by the marginal resource.  As a result, the traditional incentive and \nability to exercise market power are substantially reduced.  \n33. \nWhile the pay-as-bid design on its own does not eliminate market power concerns, \nthe overall proposed RBP design further mitigates market power concerns.  This is \ndriven by the one-time nature of the procurement, the voluntary participation \nmodel, the limited scope and bilateral process, and the maximum willingness to \npay.  In a pay-as-bid approach, unlike a uniform clearing price construct where \nsellers are expected to offer a marginal cost, sellers are more likely to offer the \nexpected clearing price.  Given offers will likely have less variation and information \nunderlying offers it can be difficult and ineffective to determine offers exhorting \nmarket power. \n34. \nThe procurement is voluntary, meaning suppliers can simply choose to participate \nor not, and then further PJM is proposing a maximum willingness-to-pay cap, \nwhich provides a direct limit on procurement costs even in the absence of offer \nmitigation.  The illustrative example below demonstrates the inability for one \nresource to impact the clearing price of any other resource in a pay-as-bid structure.   \n \n \n \n3 2025 Periodic Review of Variable Resource Requirement Curve Shape and Key Parameters, PJM \nInterconnection, \nL.L.C. \n(Nov. \n7, \n2025), \nhttps://www.pjm.com/pjmfiles/directory/etariff/FercDockets/9248/20251107-er25-455-000.pdf \n[https://perma.cc/87GP-AYL5]."},{"page":10,"startToken":3452,"endToken":3765,"text":"9 \nThis is in contrast to a uniform clearing price market where the marginal resource \nwill set the clearing price and all resources will receive that price.  A Seller has a \nfleet of three resources:  A, B, and C and offers accordingly: \nResource A @$10/MW-day  \nResource B @$10/MW-day \nResource C @$50/MW-day \nUniform-clearing price structure:   \n• Resource C sets the market-clearing price at $50/MW-day,  \n• Resource A and Resource B also receive the market-clearing price \nof $50/MW-day \nPay-as-bid structure: \n• Resource C receives offer price of $50/MW-day \n• Resource A receives offer price of $10/MW-day \n• Resource B receives offer price of $10/MW-day  \n35. \nThe Request for Information (“RFI”)4 PJM conducted shows a large set of potential \nsupply to participate in the RBP or could otherwise pursue a commercial bilateral \ncontract (via PJM’s Bilateral Matching or independently) which allows the RBP to \nfunction more like a competitive solicitation. \n36. \nIn summary, given the one-time nature of the procurement, the pay-as-bid design, \nthe voluntary participation, and the limited scope/bilateral parallel, the \nimplementation complexity and effectiveness would likely outweigh any \ncorresponding benefits and therefore PJM proposes to proceed without additional \nmarket power mitigation measures, beyond the maximum willingness to pay.  \nVIII. CONTRACT FOR DIFFERENCE  \n37. \nCfD is a financial settlement methodology for energy contracts designed to provide \nprice stability to both the buyer (load) and seller (supply).  It is structured around a \n“strike price” where the settlement or CfD is based on a difference between the \nmarket price and a committed strike price.  If the strike price is higher than the \nmarket price, the buyer must pay the difference between the strike price and market \n \n4 Charles River Associates, PJM Reliability Backstop RFI Summary, PJM Interconnection, L.L.C. (May 27, \n2026), \nhttps://www.pjm.com/-/media/DotCom/committees-groups/cifp-rbp/2026/20260527/20260527-\ninformational-only---reliability-backstop-rfi-summary---charles-river-associates.pdf \n[https://perma.cc/UM8V-FAC5]."},{"page":11,"startToken":3765,"endToken":4235,"text":"10 \nprice.  Alternatively, if the strike price is lower than the market price the seller must \npay back the difference between the strike price and market price.  \n38. \nPJM is proposing to settle the RBP with a CfD-like structure, where the strike price \nwill be the RBP offer price of the committed RBP Resource for an applicable \nDelivery Year, and the market price will be the weighted average RPM clearing \nprices for the same applicable Delivery Year. \n39. \nPJM is proposing the CfD will only be assessed for MW that are committed in the \nRPM and delivered and will be capped at RBP committed MW. This is to say there \nwill not be a CfD on RBP Resource committed MW that are not delivered in the \napplicable Delivery Year.  This is a deviation from the purely financial CfD where \nthe settlement would be on the committed amount, not what was physically \ndelivered.  PJM’s design choice of not designing a fully financial CfD was driven \nby the underscoring goal of the RBP supporting reliability and resource adequacy, \nand intended to preserve market participation while creating a more stable capacity \nrevenue stream for the RBP Resource. \nIX. \nRBP COST ALLOCATION METHODOLOGY  \n40. \nAs a wholesale market operator, PJM’s role is to design and administer a \nprocurement mechanism that addresses regional reliability needs in a manner \nconsistent with our regulatory framework.  Cost allocation decisions should \ntherefore be grounded in principles that appropriately assign costs to beneficiaries \n(demand) while respecting the jurisdictional boundaries between wholesale market \noperations and retail rate design.  This jurisdictional reality was also recognized in \nthe Statement of Principles Regarding PJM signed by the National Energy \nDominance Council and the 13 governors of the PJM states, issued on January 16, \n2026, where PJM’s 13 governors agreed to:  \n[u]se their Authorities to Allocate Costs to Data Centers and Protect \nResidential Customers:  Use all available authorities to ensure that \ntheir state public utility commissions design rate class structures to \nensure that their states’ LSEs allocate their share of the cost to \nprocure new capacity through the Reliability Backstop Auctions to \nnew data center loads that have not otherwise procured capacity or \nagreed to be curtailable.5 \n41. \nThe cost allocation structure is designed around first allocating the Final RBP \nTarget to Electric Distributor zones/areas with forecasted load adjustment, and then \nfurther allocating the charges to LSEs based on the RBO, which permits states to \ndetermine the appropriate allocation of RBP UCAP MW to specific LSEs and/or \nend-use customers, thus allowing Relevant Electric Retail Regulatory Authorities \n(“RERRA”) to appropriately assign costs to their respective retail customers, \nincluding data centers.  Should the relevant RERRA(s) decline to communicate \n \n5 Statement of Principles Regarding PJM, National Energy Dominance Council, 2 (Jan. 16, 2026), \nhttps://www.energy.gov/documents/statement-principles-regarding-pjm [https://perma.cc/35HJ-W56E]."},{"page":12,"startToken":4235,"endToken":4566,"text":"11 \nRBO MW to the relevant Electric Distributors (which would then communicate \nthat information to PJM), PJM has proposed to apply a backup default cost \nallocation.    \nA. \nStep 1:  Allocating to Electric Distributor Zone/Area \n42. \nTo allocate costs, i.e., RBP Charges, PJM is proposing to determine cost \nresponsibility by starting with the Initial RBP Target and determining how \nresponsibility for the RBP UCAP MW in the Initial RBP Target should be \nallocated.   \n43. \nFirst, the total region-wide Initial RBP Target is allocated to each Electric \nDistributor zone/area in accordance with Schedule 8 of the RAA, which was revised \nin 2024 to incorporate Load Adjustments by Electric Distributor zone/area.  More \nspecifically, the allocation of RBP UCAP MW to specific Electric Distributor \nzones/areas will be based on the forecasted load growth from the 2026/2027 \nDelivery Year to the 2028/2029 Delivery Year and incorporate the Load \nAdjustments set forth in PJM Table B9b from the 2026 PJM Load Forecast6 to \nultimately determine the initial allocated pro-rata share to each relevant Electric \nDistributor zone/area.    \n44. \nSecond, the pro-rata allocation of RBP UCAP MW to each Electric Distributor’s \nzone/area, and the Final RBP Target, will be further adjusted to reflect reductions \nfor Qualifying RBP Offset UCAP MW and UCAP MW representing successfully \nsupported opt-outs from RBP in each zone/area.  RBP Charges are then allocated \nto each Electric Distributor’s zone/area based on the zone/area’s pro-rata share of \nthe total region-wide Final RBP Target. \n45. \nAn illustrative example of these adjustments and the pro-rata allocation process is \ndetailed below. \n \n6 2026 PJM Load Forecast Report Data Tables, PJM Interconnection, L.L.C., Tab Table B9b (Feb. 2026), \nhttps://www.pjm.com/-/media/DotCom/planning/res-adeq/load-forecast/2026-load-report-tables.xlsx \n[https://perma.cc/SST2-EGUZ]; 2026 PJM Load Forecast Report, PJM Interconnection, L.L.C., 5-6 (Jan. \n14, \n2026), \nhttps://www.pjm.com/-/media/DotCom/library/reports-notices/load-forecast/2026-load-\nreport.pdf [https://perma.cc/J24E-7CV7] (describing Table B9b results)."},{"page":13,"startToken":4566,"endToken":4839,"text":"12 \nB. \nExample of Allocation to Electric Distributor Zone/Area \n46. \nThe initial allocation of RBP UCAP MW to each Electric Distributor zone/area will \nbe  based on Load Adjustments, as set forth in PJM Table B9b from the 2026 PJM \nLoad Forecast, and each zone/area’s share of the Initial RBP Target of 6,831.3 MW. \n \n47. \nSecond, as decrements are submitted, both the Final RBP Target and the pro-rata \nallocation to each Electric Distributor zone/area will be updated.  In this example, \nI will assume the following Qualifying RBP Offset UCAP MW were submitted and \nwill decrement the Initial RBP Target: \n \nMW load \nadjustment\n(2028-2026)\nBGE\n                   25.0 \n0.28%\n18.9\n                      \nPECO\n                264.0 \n2.92%\n199.6\n                    \nPPL\n             1,085.0 \n12.01%\n820.5\n                    \nPSEG\n                320.0 \n3.54%\n242.0\n                    \nAEPOHIO\n             2,019.2 \n22.35%\n1,527.0\n                \nPE\n                154.0 \n1.70%\n116.5\n                    \nPP\n                   17.8 \n0.20%\n13.5\n                      \nOHIO\n                149.2 \n1.65%\n112.8\n                    \nCOMED\n             1,173.0 \n12.99%\n887.1\n                    \nDAY\n                277.0 \n3.07%\n209.5\n                    \nDOM\n                982.6 \n10.88%\n743.1\n                    \nNVEC\n             1,722.4 \n19.07%\n1,302.6\n                \nODEC\n                170.2 \n1.88%\n128.7\n                    \nREC\n                673.8 \n7.46%\n509.6\n                    \n RTO\n           9,033.2 \n100%                6,831.3 \nAREANAME\nInitial Share \nof RBP (%)\nInitial \nAllocation of \nRBP UCAP MW\nREC\n673.8\n633.4\nODEC\n130\n122.2\nAREANAME Load\nQualifying \nRBP Offset \nUCAP MW\nNote: The qualifying RBP Offset UCAP MW is \nrepresented by load*FPR for the 2028/2029 \nBRA (0.9401).  This is representative of the \nself-supply obligation."},{"page":14,"startToken":4839,"endToken":5158,"text":"13 \n48. \nIn my illustrative example, for purposes of simplicity, I assume there are no \nadditional decrements to the Initial RBP Target for opt outs.  Thus, the Final RBP \nTarget would be calculated as Initial RBP target – Qualifying RBP Offset UCAP \nMW.  In this example, this would be: 6,831.3 MW – [633.4 MW + 122.2 MW ] = \n6,075.7 MW.  The Qualifying RBP Offset UCAP MW is divided by the 2028/2029 \nBRA Forecast Pool Requirement to identify the amount of load that is being served \nby those offset MW and can subsequently be removed from any allocation of RBP \nMW.   \n49. \nThe updated allocation would be as follows, as demonstrated in the table below.  In \nthe Old Dominion Electric Cooperative (“ODEC”) zone/area, the MW Load \nAdjustment is reduced from 170.2 MW to 40.2 MW to account for the 130 MW of \nload with demonstrated Qualifying RBP Offset UCAP MW.  In the Rappahannock \nElectric Cooperative (“REC”) zone/area, the MW Load Adjustment is reduced to 0 \nMW, from 673.8 MW to 0 MW to account for the 673.8 MW of load with \ndemonstrated Qualifying RBP Offset UCAP MW.   \n50. \nBased on the revised adjustments to the Load Adjustments, each Electric \nDistributor zone/area’s allocated RBP UCAP MW will reflect its adjusted pro-rata \nshare of the 6,075.7 MW Final RBP Target.  Thus, while ODEC had previously \nbeen allotted 1.88% of the Initial Target, its pro-rata share was reduced to 0.49% to \nreflect the fact that ODEC brought 122.2 MW of Qualifying RBP Offset UCAP \nMW, which is, with the Forecast Pool Requirement adjustment, equivalent to 130 \nMW.  Similarly, REC’s pro-rata share went from 7.46% to 0.0% to reflect that REC \nbrought 633.4 MW UCAP supply, which is obligation for 673.8 MW of load, and \nis equal to the amount of the REC Load Adjustment."},{"page":15,"startToken":5158,"endToken":5540,"text":"14 \n \nC. \nStep 2:  Allocating to LSEs and/or End-Use Customers Based on \nRERRA-Determined Allocation or Allocating to LSEs Based on PJM \nBackup Allocation \n51. \nElectric Distributors will report to PJM, where available, the RBO MW for the \nLSEs in an Electric Distributor’s zone/area that are being allocated RBP UCAP \nMW.  These value(s) will be provided to PJM by the Electric Distributor designated \nto coordinate with the states and/or RERRAs to the extent that states and/or \nRERRAs wish to provide the Electric Distributors with information on how costs \nare allocated to LSEs.  To the extent that PJM assigns costs to LSEs in accordance \nwith RBO MW, PJM does so at the direction of the submitted information by \nrelevant the Electric Distributor(s) as determined by the RERRA for that zone/area. \n52. \nIf PJM does not receive RBO MW from an Electric Distributor for a zone/area \nallocated RBP UCAP MW, PJM will need a backup settlement allocation.  PJM \nwill assign the RBP UCAP MW using the Daily Unforced Capacity Obligation MW \nload ratio shares in the respective zone/area that are assigned RBP UCAP MW.    \nD. \nExample of Allocation to Electric Distributor Zone/Area \n53. \nAnother illustrative example is detailed below for the pro-rata allocation process to \nthe LSEs that are being allocated RBP UCAP MW.  In this example, we assume \nthe Electric Distributor zone/area 1 has 116 RBP UCAP MW obligation with an \nassociated $11,600/day RBP charge, allocated to that zone/area.  There are two \nFinal MW \nload \nadjustment\n(2028-2026)\nBGE\n                   25.0 \n0.30%\n18.5\n                      \nPECO\n                264.0 \n3.21%\n194.9\n                    \nPPL\n             1,085.0 \n13.18%\n801.0\n                    \nPSEG\n                320.0 \n3.89%\n236.3\n                    \nAEPOHIO\n             2,019.2 \n24.54%\n1,490.8\n                \nPE\n                154.0 \n1.87%\n113.7\n                    \nPP\n                   17.8 \n0.22%\n13.1\n                      \nOHIO\n                149.2 \n1.81%\n110.2\n                    \nCOMED\n             1,173.0 \n14.25%\n866.0\n                    \nDAY\n                277.0 \n3.37%\n204.5\n                    \nDOM\n                982.6 \n11.94%\n725.4\n                    \nNVEC\n             1,722.4 \n20.93%\n1,271.6\n                \nODEC\n                   40.2 \n0.49%\n29.7\n                      \nREC\n0.0 \n0.00%\n0.0\n RTO\n           8,229.4 \n100%                6,075.7 \nFinal Share \nof RBP (%)\nFinal \nAllocation of \nRBP UCAP MW\nAREANAME"},{"page":16,"startToken":5540,"endToken":5768,"text":"15 \nLSEs (i.e., LSE 1 and LSE 2) in zone/area 1 that bear some responsibility for the \nRBP charge, based on the RBO submitted to PJM.  \n54. \nIn the first scenario, the designated RBO MW that should be used to allocate \ncharges to each LSE is submitted to PJM by the Electric Distributor and then PJM \nwill apply the cost allocation and settle RBP Charges accordingly.  Here, the \nreported RBO MW for LSE 1 is 58 RBP UCAP MW, for LSE 2 is 58 RBP UCAP \nMW, and for LSE 3 is 0 RBP UCAP MW.  Thus the $11,600/day RBP Charges \nwill be allocated pro rata 50% to LSE 1, 50% to LSE2, and 0% to LSE 3. \n \n \n55. \nIn the second scenario, where the submitted RBO MW is not equal to the RBP \nUCAP MW procured for the zone/area, PJM will still use the submitted RBO MW \nto determine the pro rata allocation and ensure the RBP Charges are fully allocated \nto the LSE’s with non-zero submitted obligations.  In the example below, LSE 1 is \n60 RBP UCAP MW, LSE 2 is 40 RBP UCAP MW, and LSE 3 is 0 RBP UCAP \nMW.  Thus, the $11,600/day RBP Charge will be allocated 60% to LSE1 and 40% \nto LSE 2, and 0% to LSE 3.  \n \n \n56. \nThis concludes my affidavit."},{"page":17,"startToken":5768,"endToken":5783,"text":"Exhibit 1 \nAppendix to Affidavit of Ms. Danielle Croop \nExamples Demonstrating RBP Resource \nProcurement Process"},{"page":18,"startToken":5783,"endToken":6007,"text":"Croop, Exhibit No. 1 \nPage 1 \n \n \nExamples Demonstrating RBP Resource Procurement Process \nThe following examples are intended to demonstrate how RBP Resources will be procured \nbased on a maximum willingness to pay, defined as a “MW-weighted average of the levelized \nprocurement cost” for the RBP, and selected through a “budget approach.”1  \nEach RBP Resource Sell Offer will include an offer price and MW quantity pair for each \nDelivery Year beginning with the first year the resource is expected to reach commercial operation.  \nPJM will then determine the “levelized procurement cost” for this resource to use in the selection \nprocess.2  This will be done with the Levelized Cost equation, with a discount rate equal to 9.5% \nafter-tax average weighted average cost of capital (“ATWACC”).  \nLevelized Cost ($/MW-day) = Net Present Value (RBP Sell Offer price x UCAP \noffered)/Net Present Value (UCAP offered)  \n \nExample 1 \nIn the example below, Unit A offers at a price and a quantity for each Delivery Year of the \n15-year fixed term, beginning in Year 1 and ending in Year 15.  This Offer has a levelized \nprocurement cost of $101.50/MW-day UCAP and a levelized MW value of 69.3 MW. \n \n1 Proposed Tariff, Attachment DD, section 18.5(f)(ii); Croop Aff. ¶ 29. \n2 Proposed Tariff, Attachment DD, section 18.5(f)(ii); Croop Aff. ¶ 29."},{"page":19,"startToken":6007,"endToken":6210,"text":"Croop, Exhibit No. 1 \nPage 2 \n \n \nExample 1: Unit A, $/MW Offer per Year \n \nUnit A \nPrice ($) \nMW \nYear 1 \n91 \n10 \nYear 2 \n91 \n10 \nYear 3 \n100 \n9 \nYear 4 \n100 \n9 \nYear 5 \n100 \n9 \nYear 6 \n100 \n9 \nYear 7 \n100 \n9 \nYear 8 \n110 \n8 \nYear 9 \n110 \n8 \nYear 10 \n110 \n8 \nYear 11 \n110 \n8 \nYear 12 \n110 \n8 \nYear 13 \n110 \n8 \nYear 14 \n110 \n8 \nYear 15 \n110 \n8 \n \n \nExample 2 \nExample 2 walks through how a set of offers are evaluated based on ranked Delivery Year \nand levelized cost for selection. The selection process is also constrained to the maximum \nwillingness to pay of the procurement.  For illustrative purposes, rather than a maximum \nwillingness to pay of $555/MW-day as PJM is proposing to use for the RBP, we assume that the \nmaximum willingness to pay is $100/MW-day, and the Final RBP Target for procurement is \n6,800 MW.   \nTable 1 illustrates the UCAP MW offered through the first four Delivery Years and a \nrepresented levelized cost offer for this resource.  Table 1, below, tracks the MW that are procured \nto determine when PJM satisfies the procurement target of 6,800 MW."},{"page":20,"startToken":6210,"endToken":6600,"text":"Croop, Exhibit No. 1 \nPage 3 \n \n \nTable 1 \n \n \nTable 2 shows the offers in greater detail in determining the present value and levelized cost of the \noffers.  For each RBP Resource offer (Offers 1-8), there are three procurement values in the PV \ncolumn.  The first value for each RBP Resource offer is the levelized MW UCAP.  The second \nvalue is the levelized cost, expressed as $/MW-day.  And the third value is the total revenue cost \nstream based on the RBP Resource’s levelized MW and cost.  \nTable 2 \n \n28/29\n29/30\n30/31\n31/32\nLevelized Cost Offer\nOffer 1\n3,000\n                                      \n3,000\n                         \n2,800\n                         \n2,800\n                         \n$100\nOffer 2\n500\n                                           \n450\n                              \n450\n                              \n400\n                              \n$50\nOffer 3\n400\n                              \n500\n                              \n500\n                              \n$200\nOffer 4\n2,000\n                         \n1,900\n                         \n2,000\n                         \n$50\nOffer 5\n900\n                              \n1,000\n                         \n1,000\n                         \n$90\nOffer 6\n150\n                              \n150\n                              \n$1,200\nOffer 7\n200\n                              \n$1,500\nOffer 8\n200\n                              \n$2,000\nTotal Offered\n3,500\n                                      \n6,750\n                         \n6,800\n                         \n7,250\n                         \n28/29\n29/30\n30/31\n31/32\nPV\nMW UCAP\n3,000\n                      \n3,000\n                      \n2,800\n                      \n2,800\n                                   \n9,322\n               \n$/MW-Day \n$100\n$100\n$100\n$100\n$100\nRevenue Cost Stream\n$300,000\n$300,000\n$280,000\n$280,000\n$932,200\nMW UCAP\n500\n                           \n450\n                           \n450\n                           \n400\n                                        \n1,453\n               \n$/MW-Day \n$50\n$50\n$50\n$50\n$50\nRevenue Cost Stream\n$25,000\n$22,500\n$22,500\n$20,000\n$72,645\nMW UCAP\n-\n                            \n400\n                           \n500\n                           \n500\n                                        \n1,062\n               \n$/MW-Day \n$0\n$200\n$200\n$200\n$200\nRevenue Cost Stream\n$0\n$80,000\n$100,000\n$100,000\n$212,444\nMW UCAP\n-\n                            \n2,000\n                      \n1,900\n                      \n2,000\n                                   \n4,506\n               \n$/MW-Day \n$0\n$50\n$50\n$50\n$50\nRevenue Cost Stream\n$0\n$100,000\n$95,000\n$100,000\n$225,316\nMW UCAP\n-\n                            \n900\n                           \n1,000\n                      \n1,000\n                                   \n2,208\n               \n$/MW-Day \n$0\n$90\n$90\n$90\n$90\nRevenue Cost Stream\n$0\n$81,000\n$90,000\n$90,000\n$198,705\nMW UCAP\n-\n                            \n-\n                            \n150\n                           \n150\n                                        \n219\n                    \n$/MW-Day \n$0\n$0\n$300\n$300\n$300\nRevenue Cost Stream\n$0\n$0\n$45,000\n$45,000\n$65,575\nMW UCAP\n-\n                            \n-\n                            \n-\n                            \n200\n                                        \n139\n                    \n$/MW-Day \n$0\n$0\n$0\n$300\n$300\nRevenue Cost Stream\n$0\n$0\n$0\n$60,000\n$41,734\nMW UCAP\n-\n                            \n-\n                            \n-\n                            \n200\n                                        \n139\n                    \n$/MW-Day \n$0\n$0\n$0\n$300\n$300\nRevenue Cost Stream\n$0\n$0\n$0\n$60,000\n$41,734\nOffer 8\nOffer 1\nOffer 2\nOffer 3\nOffer 4\nOffer 5\nOffer 6\nOffer 7"},{"page":21,"startToken":6600,"endToken":6868,"text":"Croop, Exhibit No. 1 \nPage 4 \n \n \nThe procurement process will prioritize earlier Delivery Years, while being constrained to the \nfixed-budget maximum willingness to pay.  This can result in: (1) an earlier Delivery Year resource \nbeing skipped if it will violate the maximum willingness to pay constraint; (2) a procurement of \nthat resource later in the process, even if the resource was previously skipped, if procurement of a \nlower-priced resource creates additional cost headroom in the budget; and/or (3) a possibility that \nPJM will not procure the exact Final RBP Target quantity if doing so violates the maximum \nwillingness to pay constraint.  These features are demonstrated below in the selection sequencing \nexample: \nStep 1: Procure Offer 1. This will add the below MW value to the target for each Delivery \nYear, with a MW-weighted average levelized costs of $100.  \n \nStep 2: Procure Offer 2. This will increase our procurement by the offered MW for each \napplicable Delivery Year, and result in a MW-weighted average levelized cost of $93.26. \n \nThe MW-weighted average levelized cost of $93.26 can be calculated from the PV column in \nTable 2 as the sum of levelized MW / sum of Revenue cost stream.  [9,322+1,453]/[932,200 + \n72,645] \n \n28/29\n29/30\n30/31\n31/32\nOffer 1\n3,000\n                                      \n3,000\n                         \n2,800\n                         \n2,800\n                         \nTotal Offered\n3,000\n                                      \n3,000\n                         \n2,800\n                         \n2,800\n                         \n28/29\n29/30\n30/31\n31/32\nOffer 1\n3,000\n                                      \n3,000\n                         \n2,800\n                         \n2,800\n                         \nOffer 2\n500\n                                           \n450\n                              \n450\n                              \n400\n                              \nTotal Offered\n3,500\n                                      \n3,450\n                         \n3,250\n                         \n3,200"},{"page":22,"startToken":6868,"endToken":7174,"text":"Croop, Exhibit No. 1 \nPage 5 \n \n \nStep 3: Skip Offer 3. If Offer 3 was selected the MW-weighted average levelized cost \nwould rise to $102.84, above the maximum willingness to pay of $100 MW/day. \nStep 4: Procure Offer 4. This will increase the procured MW by the offered MW for each \napplicable Delivery Year, and result in a MW-weighted average levelized cost of $80.50.\n \nStep 5: Procure Offer 3.  Offer 3 may now be procured while keeping the MW-weighted \naverage levelized cost under the maximum willingness to pay.  Thus, the procurement will \nprioritize and commit this resource with an earlier first Delivery Year.  This will increase the \nprocured MW by the offered MW for each applicable Delivery Year, and result in a MW-weighted \naverage levelized cost of $88.27. \n \nStep 6: Procure Offer 5. This will increase the procured MW by the offered MW for each \napplicable Delivery Year, and result in a MW-weighted average levelized cost of $88.47.\n \n28/29\n29/30\n30/31\n31/32\nOffer 1\n3,000\n                                      \n3,000\n                         \n2,800\n                         \n2,800\n                         \nOffer 2\n500\n                                           \n450\n                              \n450\n                              \n400\n                              \nOffer 4\n2,000\n                         \n1,900\n                         \n2,000\n                         \nTotal Offered\n3,500\n                                      \n5,450\n                         \n5,150\n                         \n5,200\n                         \n28/29\n29/30\n30/31\n31/32\nOffer 1\n3,000\n                                      \n3,000\n                         \n2,800\n                         \n2,800\n                         \nOffer 2\n500\n                                           \n450\n                              \n450\n                              \n400\n                              \nOffer 3\n400\n                              \n500\n                              \n500\n                              \nOffer 4\n2,000\n                         \n1,900\n                         \n2,000\n                         \nTotal Offered\n3,500\n                                      \n5,850\n                         \n5,650\n                         \n5,700\n                         \n28/29\n29/30\n30/31\n31/32\nOffer 1\n3,000\n                                      \n3,000\n                         \n2,800\n                         \n2,800\n                         \nOffer 2\n500\n                                           \n450\n                              \n450\n                              \n400\n                              \nOffer 3\n400\n                              \n500\n                              \n500\n                              \nOffer 4\n2,000\n                         \n1,900\n                         \n2,000\n                         \nOffer 5\n900\n                              \n1,000\n                         \n1,000\n                         \nTotal Offered\n3,500\n                                      \n6,750\n                         \n6,650\n                         \n6,700"},{"page":23,"startToken":7174,"endToken":7341,"text":"Croop, Exhibit No. 1 \nPage 6 \n \n \nStep 7: Procure Offer 6. This will increase the procured MW by the offered MW for each \napplicable Delivery Year, and result in a MW-weighted average levelized cost of $90.94 \n \nAt this point, the final target MW of 6,800 has been committed and the procurement is complete.  \nOffer 7 and 8 would not be procured through the RBP.  \n \nExample 3 \nIn Example 3, the selection clears short of the Final RBP Target to maintain the maximum \nwillingness to pay.  This example relies on the same example as above, except that offer prices for \nOffers 6, 7, and 8 are dramatically increased.   \n28/29\n29/30\n30/31\n31/32\nOffer 1\n3,000\n                                  \n3,000\n                      \n2,800\n                      \n2,800\n                      \nOffer 2\n500\n                                      \n450\n                           \n450\n                           \n400\n                           \nOffer 3\n400\n                           \n500\n                           \n500\n                           \nOffer 4\n2,000\n                      \n1,900\n                      \n2,000\n                      \nOffer 5\n900\n                           \n1,000\n                      \n1,000\n                      \nOffer 6\n150\n                           \n150\n                           \nTotal Offe\n3,500\n                                  \n6,750\n                      \n6,800\n                      \n7,250"},{"page":24,"startToken":7341,"endToken":7691,"text":"Croop, Exhibit No. 1 \nPage 7 \n \n \nTable 3 \n \nThe procurement process runs through Steps 1 through 5, as described in Example 2, above.  Then, \nstarting in Step 6, the process begins to differ:  \nStep 6: Procure Offer 5. This will increase the procured MW by the offered MW for each \napplicable Delivery Year, and result in a MW-weighted average levelized cost of $88.47. \n \n28/29\n29/30\n30/31\n31/32\nPV\nMW UCAP\n3,000\n                      \n3,000\n                      \n2,800\n                      \n2,800\n                                   \n9,322\n               \n$/MW-Day \n$100\n$100\n$100\n$100\n$100\nRevenue Cost Stream\n$300,000\n$300,000\n$280,000\n$280,000\n$932,200\nMW UCAP\n500\n                           \n450\n                           \n450\n                           \n400\n                                        \n1,453\n               \n$/MW-Day \n$50\n$50\n$50\n$50\n$50\nRevenue Cost Stream\n$25,000\n$22,500\n$22,500\n$20,000\n$72,645\nMW UCAP\n-\n                            \n400\n                           \n500\n                           \n500\n                                        \n1,062\n               \n$/MW-Day \n$0\n$200\n$200\n$200\n$200\nRevenue Cost Stream\n$0\n$80,000\n$100,000\n$100,000\n$212,444\nMW UCAP\n-\n                            \n2,000\n                      \n1,900\n                      \n2,000\n                                   \n4,506\n               \n$/MW-Day \n$0\n$50\n$50\n$50\n$50\nRevenue Cost Stream\n$0\n$100,000\n$95,000\n$100,000\n$225,316\nMW UCAP\n-\n                            \n900\n                           \n1,000\n                      \n1,000\n                                   \n2,208\n               \n$/MW-Day \n$0\n$90\n$90\n$90\n$90\nRevenue Cost Stream\n$0\n$81,000\n$90,000\n$90,000\n$198,705\nMW UCAP\n-\n                            \n-\n                            \n150\n                           \n150\n                                        \n219\n                    \n$/MW-Day \n$0\n$0\n$1,500\n$1,500\n$1,500\nRevenue Cost Stream\n$0\n$0\n$225,000\n$225,000\n$327,876\nMW UCAP\n-\n                            \n-\n                            \n-\n                            \n200\n                                        \n139\n                    \n$/MW-Day \n$0\n$0\n$0\n$1,500\n$1,500\nRevenue Cost Stream\n$0\n$0\n$0\n$300,000\n$208,672\nMW UCAP\n-\n                            \n-\n                            \n-\n                            \n200\n                                        \n139\n                    \n$/MW-Day \n$0\n$0\n$0\n$2,000\n$2,000\nRevenue Cost Stream\n$0\n$0\n$0\n$400,000\n$278,230\nOffer 8\nOffer 1\nOffer 2\nOffer 3\nOffer 4\nOffer 5\nOffer 6\nOffer 7\n28/29\n29/30\n30/31\n31/32\nOffer 1\n3,000\n                                      \n3,000\n                         \n2,800\n                         \n2,800\n                         \nOffer 2\n500\n                                           \n450\n                              \n450\n                              \n400\n                              \nOffer 3\n400\n                              \n500\n                              \n500\n                              \nOffer 4\n2,000\n                         \n1,900\n                         \n2,000\n                         \nOffer 5\n900\n                              \n1,000\n                         \n1,000\n                         \nTotal Offered\n3,500\n                                      \n6,750\n                         \n6,650\n                         \n6,700"},{"page":25,"startToken":7691,"endToken":7796,"text":"Croop, Exhibit No. 1 \nPage 8 \n \n \nAt this point, Offers 6, 7 and 8 cannot be procured without violating the maximum \nwillingness to pay constraint.  If Offer 6 were selected, the MW-weighted average levelized cost \nwould rise to $104.91, which is above the maximum willingness to pay of $100 MW/day.  Similar \nviolations of the maximum willingness to pay for Offers 7, and 8 would occur.  Given that, in this \nexample, there are no additional offers to consider, the procurement would clear 100 MW short \nthe target, with the maximum UCAP MW procured equal to 6,700 MW for the 2031/32 Delivery \nYear."},{"page":26,"startToken":7796,"endToken":7950,"text":"UNITED STATES OF AMERICA\nBEFORE THE\nFEDERAL ENERGY REGULATORY COMMISSION\nPJM Interconnection, L.L.C.\n)\nDocket No. ER26-\n-000\nVERIFICATION\nI, Danielle Croop, pursuant to 28 U.S.C. § 1746, state, under penalty of perjury,\nthat I am the Danielle Croop referred to in the foregoing document entitled \"Affidavit of\nDanielle Croop, on Behalf of P.JM Interconnection, L.L.C.ại that I have read the same and\nam familiar with the contents thereof, and that the facts set forth therein are true and correct\nto the best of my knowledge, information, and belief.\nDanielle Croop\nDanielle Croop\nSr. Manager\nMarket Design\nP.JM Interconnection, L.L.C.\nSubscribed and sworn to before me, the undersigned notary public, this 31st day\nof July 2026.\nNechilti: Nattiok\nMy Commision expires: /9/23/3427\nCommonwealth of Pennsylvania • Notary Seal\nMICHELE A MATTICOLA - Notary Public\nMontgomery County\nMy Commission Expires December 23, 2027\nCommission Number 1249359"}],"sections":[{"p":1,"at":0,"title":"Attachment C","method":"printed heading","endPage":3,"endAt":998,"startToken":0,"endToken":493},{"p":3,"at":998,"title":"I. KEY DESIGN CONSIDERATIONS AND RATIONALE","method":"printed heading","endPage":4,"endAt":395,"startToken":493,"endToken":909},{"p":4,"at":395,"title":"II. REGION-WIDE PROCUREMENT OF RBP RESOURCES","method":"printed heading","endPage":4,"endAt":1885,"startToken":909,"endToken":1126},{"p":4,"at":1885,"title":"III. INTENTIONALLY","method":"printed heading","endPage":5,"endAt":3,"startToken":1126,"endToken":1265},{"p":5,"at":3,"title":"A. Supply Eligible to Reduce Initial RBP Target","method":"printed heading","endPage":5,"endAt":1365,"startToken":1265,"endToken":1468},{"p":5,"at":1365,"title":"B. Supply Eligible to Participate as RBP Resources in the RBP","method":"printed heading","endPage":7,"endAt":882,"startToken":1468,"endToken":2269},{"p":7,"at":882,"title":"IV. PAY-AS-BID STRUCTURE","method":"printed heading","endPage":8,"endAt":125,"startToken":2269,"endToken":2586},{"p":8,"at":125,"title":"V. VOLUME-WEIGHTED","method":"printed heading","endPage":8,"endAt":2162,"startToken":2586,"endToken":2919},{"p":8,"at":2162,"title":"VI. SELECTION PROCESS","method":"printed heading","endPage":9,"endAt":956,"startToken":2919,"endToken":3188},{"p":9,"at":956,"title":"VII. MARKET MITIGATION","method":"printed heading","endPage":10,"endAt":1355,"startToken":3188,"endToken":3654},{"p":10,"at":1355,"title":"VIII. CONTRACT FOR DIFFERENCE","method":"printed heading","endPage":11,"endAt":1149,"startToken":3654,"endToken":3959},{"p":11,"at":1149,"title":"IX. RBP COST ALLOCATION METHODOLOGY","method":"printed heading","endPage":12,"endAt":171,"startToken":3959,"endToken":4261},{"p":12,"at":171,"title":"A. Step 1: Allocating to Electric Distributor Zone/Area","method":"printed heading","endPage":13,"endAt":4,"startToken":4261,"endToken":4567},{"p":13,"at":4,"title":"B. Example of Allocation to Electric Distributor Zone/Area","method":"printed heading","endPage":15,"endAt":6,"startToken":4567,"endToken":5159},{"p":15,"at":6,"title":"C. Step 2: Allocating to LSEs and/or End-Use Customers Based on","method":"printed heading","endPage":15,"endAt":1120,"startToken":5159,"endToken":5348},{"p":15,"at":1120,"title":"D. Example of Allocation to Electric Distributor Zone/Area","method":"printed heading","endPage":26,"endAt":943,"startToken":5348,"endToken":7950}]}