{"document":{"slug":"filing-er26-3380-pjm-original-attachment-2","title":"Attachment B - Clean Tariff Records.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_03.pdf","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_Number=20260731-5214","parent":"filing-er26-3380-pjm-original","sha256":"b359e6150f6323d9178d079475f84129fd63b5bb68c73a6f1db01ad7d8d9963f","pages":165,"tokens":64428,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":17,"text":"Attachment B \nRevisions to the \nPJM Open Access Transmission Tariff \nand PJM Reliability Assurance \nAgreement \n(Clean Format)"},{"page":2,"startToken":17,"endToken":289,"text":"Definitions – C - D \n \nCanadian Guaranty: \n \n“Canadian Guaranty” shall mean a Corporate Guaranty provided by an Affiliate of a Participant \nthat is domiciled in Canada, and meets all of the provisions of Tariff, Attachment Q. \n \nCancellation Costs: \n \n“Cancellation Costs” shall mean costs and liabilities incurred in connection with: (a) cancellation \nof supplier and contractor written orders and agreements entered into to design, construct and \ninstall Attachment Facilities, Direct Assignment Facilities and/or Customer-Funded Upgrades, \nand/or (b) completion of some or all of the required Attachment Facilities, Direct Assignment \nFacilities and/or Customer-Funded Upgrades, or specific unfinished portions and/or removal of \nany or all of such facilities which have been installed, to the extent required for the Transmission \nProvider and/or Transmission Owner(s) to perform their respective obligations under Tariff, Part \nIV and/or Part VI. \n \nCapacity: \n \n“Capacity” shall mean the installed capacity requirement of the Reliability Assurance Agreement \nor similar such requirements as may be established. \n \nCapacity Emergency Transfer Limit: \n \n“Capacity Emergency Transfer Limit” or “CETL” shall have the meaning provided in the \nReliability Assurance Agreement. \n \nCapacity Emergency Transfer Objective: \n \n“Capacity Emergency Transfer Objective” or “CETO” shall have the meaning provided in the \nReliability Assurance Agreement. \n \nCapacity Export Transmission Customer: \n \n“Capacity Export Transmission Customer” shall mean a customer taking point to point \ntransmission service under Tariff, Part II to export capacity from a generation resource located in \nthe PJM Region that has qualified for an exception to the RPM must-offer requirement as \ndescribed in Tariff, Attachment DD, section 6.6(g). \n \nCapacity Import Limit: \n \n“Capacity Import Limit” shall have the meaning provided in the Reliability Assurance \nAgreement. \n \nCapacity Interconnection Rights:"},{"page":3,"startToken":289,"endToken":653,"text":"“Capacity Interconnection Rights” shall mean the rights to input generation as a Generation \nCapacity Resource into the Transmission System at the Point of Interconnection where the \ngenerating facilities connect to the Transmission System. \n \nCapacity Market Buyer: \n \n“Capacity Market Buyer” shall mean a Member that submits bids to buy Capacity Resources in \nany Incremental Auction.   \n \nCapacity Market Seller: \n \n“Capacity Market Seller” shall mean a Member that owns, or has the contractual authority to \ncontrol the output or load reduction capability of, a Capacity Resource, that has not transferred \nsuch authority to another entity, and that offers such resource in the Base Residual Auction or an \nIncremental Auction. \n \nCapacity Performance Transition Incremental Auction: \n \n“Capacity Performance Transition Incremental Auction” shall have the meaning specified in \nTariff, Attachment DD, section 5.14D. \n \nCapacity Resource: \n \n“Capacity Resource” shall have the meaning provided in the Reliability Assurance Agreement. \n \nCapacity Resource with State Subsidy:  \n \n“Capacity Resource with State Subsidy” shall mean (1) a Capacity Resource that is offered into \nan RPM Auction or otherwise assumes an RPM commitment for which the Capacity Market \nSeller receives or is entitled to receive one or more State Subsidies for the applicable Delivery \nYear; (2) a Capacity Resource that has not cleared an RPM Auction for the Delivery Year for \nwhich the Capacity Market Seller last received a State Subsidy (or any subsequent Delivery \nYear) shall still be considered a Capacity Resource with State Subsidy upon the expiration of \nsuch State Subsidy until the resource clears an RPM Auction; (3) a Capacity Resource that is the \nsubject of a bilateral transaction (including but not limited to those reported pursuant to Tariff, \nAttachment DD, section 4.6) shall be deemed a Capacity Resource with State Subsidy to the \nextent an owner of the facility supporting the Capacity Resource is entitled to a State Subsidy \nassociated with such facility even if the Capacity Market Seller is not entitled to a State Subsidy; \nand (4) any Jointly Owned Cross-Subsidized Capacity Resource.  \n \nCapacity Resource Clearing Price: \n \n“Capacity Resource Clearing Price” shall mean the price calculated for a Capacity Resource that \noffered and cleared in a Base Residual Auction or Incremental Auction, in accordance with \nTariff, Attachment DD, section 5."},{"page":4,"startToken":653,"endToken":987,"text":"Capacity Storage Resource: \n \n“Capacity Storage Resource” shall mean any Energy Storage Resource that participates in the \nReliability Pricing Model or is otherwise treated as capacity in PJM’s markets such as through a \nFixed Resource Requirement Capacity Plan. \n \nCapacity Transfer Right: \n \n“Capacity Transfer Right” shall mean a right, allocated to LSEs serving load in a Locational \nDeliverability Area, to receive payments, based on the transmission import capability into such \nLocational Deliverability Area, that offset, in whole or in part, the charges attributable to the \nLocational Price Adder, if any, included in the Zonal Capacity Price calculated for a Locational \nDelivery Area. \n \nCapacity Transmission Injection Rights: \n \n“Capacity Transmission Injection Rights” shall mean the rights to schedule energy and capacity \ndeliveries at a Point of Interconnection of a Merchant Transmission Facility with the \nTransmission System. Capacity Transmission Injection Rights may be awarded only to a \nMerchant D.C. Transmission Facility and/or Controllable A.C. Merchant Transmission Facilities \nthat connects the Transmission System to another control area. Deliveries scheduled using \nCapacity Transmission Injection Rights have rights similar to those under Firm Point-to-Point \nTransmission Service or, if coupled with a generating unit external to the PJM Region that \nsatisfies all applicable criteria specified in the PJM Manuals, similar to Capacity Interconnection \nRights. \n \nCharge Economic Maximum Megawatts: \n \n“Charge Economic Maximum Megawatts” shall mean the greatest magnitude of megawatt power \nconsumption available for charging in economic dispatch by an Energy Storage Resource Model \nParticipant or Open-Loop Hybrid Resource in Continuous Mode or in Charge Mode.  Charge \nEconomic Maximum Megawatts shall be the Economic Minimum for an Energy Storage \nResource or Open-Loop Hybrid Resource in Charge Mode or in Continuous Mode. \n \nCharge Economic Minimum Megawatts: \n \n“Charge Economic Minimum Megawatts” shall mean the smallest magnitude of megawatt power \nconsumption available for charging in economic dispatch by an Energy Storage Resource Model \nParticipant or Open-Loop Hybrid Resource in Charge Mode.  Charge Economic Minimum \nMegawatts shall be the Economic Maximum for an Energy Storage Resource or Open-Loop \nHybrid Resource in Charge Mode. \n \nCharge Mode:"},{"page":5,"startToken":987,"endToken":1435,"text":"“Charge Mode” shall mean the mode of operation of an Energy Storage Resource Model \nParticipant or Open-Loop Hybrid Resource that only includes negative megawatt quantities (i.e., \nthe Energy Storage Resource Model Participant or Open-Loop Hybrid Resource is only \nwithdrawing megawatts from the grid).   \n \nCharge Ramp Rate: \n \n“Charge Ramp Rate” shall mean the Ramping Capability of an Energy Storage Resource Model \nParticipant or Open-Loop Hybrid Resource in Charge Mode. \n \nCleared Capacity Resource with State Subsidy: \n \n“Cleared Capacity Resource with State Subsidy” shall mean a Capacity Resource with State \nSubsidy that has cleared in an RPM Auction for a Delivery Year that is prior to the 2022/2023 \nDelivery Year or, starting with 2022/2023 Delivery Year, the MWs (in installed capacity) \ncomprising a Capacity Resource with State Subsidy that have cleared an RPM Auction pursuant \nto its Sell Offer at or above its resource-specific MOPR Floor Offer Price or the applicable \ndefault New Entry MOPR Floor Offer Price and since then, any of those MWs (in installed \ncapacity) comprising a Capacity Resource with State Subsidy have been, the subject of a Sell \nOffer into the Base Residual Auction or included in an FRR Capacity Plan at the time of the \nBase Residual Auction for the relevant Delivery Year.   \n \nClosed-Loop Hybrid Resource: \n \n“Closed-Loop Hybrid Resource” shall mean a Hybrid Resource without a storage component, or \nthat does not operate by charging its storage component from the grid. \n \nCold/Warm/Hot Notification Time: \n \n“Cold/Warm/Hot Notification Time” shall mean the time interval between PJM notification and \nthe beginning of the start sequence for a generating unit that is currently in its cold/warm/hot \ntemperature state. The start sequence may include steps such as any valve operation, starting feed \nwater pumps, startup of auxiliary equipment, etc. \n \nCold/Warm/Hot Start-up Time: \n \nFor all generating units that are not combined cycle units, “Cold/Warm/Hot Start-up Time” shall \nmean the time interval, measured in hours, from the beginning of the start sequence to the point \nafter generator breaker closure, which is typically indicated by telemetered or aggregated State \nEstimator megawatts greater than zero for a generating unit in its cold/warm/hot temperature \nstate. For combined cycle units, “Cold/Warm/Hot Start-up Time” shall mean the time interval \nfrom the beginning of the start sequence to the point after first combustion turbine generator \nbreaker closure in its cold/warm/hot temperature state, which is typically indicated by \ntelemetered or aggregated State Estimator megawatts greater than zero. For all generating units, \nthe start sequence may include steps such as any valve operation, starting feed water pumps, \nstartup of auxiliary equipment, etc. Other more detailed actions that could signal the beginning of"},{"page":6,"startToken":1435,"endToken":1801,"text":"the start sequence could include, but are not limited to, the operation of pumps, condensers, fans, \nwater chemistry evaluations, checklists, valves, fuel systems, combustion turbines, starting \nengines or systems, maintaining stable fuel/air ratios, and other auxiliary equipment necessary \nfor startup. \n \nCold Weather Alert: \n \n“Cold Weather Alert” shall mean the notice that PJM provides to PJM Members, Transmission \nOwners, resource owners and operators, customers, and regulators to prepare personnel and \nfacilities for expected extreme cold weather conditions. \n \nCollateral: \n \n“Collateral” shall be a cash deposit, including any interest thereon, or a Letter of Credit issued \nfor the benefit of PJM or PJMSettlement, in an amount and form determined by and acceptable \nto PJM or PJMSettlement, provided by a Participant to PJM or PJMSettlement as credit support \nin order to participate in the PJM Markets or take Transmission Service.  “Collateral” shall also \ninclude surety bonds, except for the purpose of satisfying the FTR Credit Requirement, in which \ncase only a cash deposit or Letter of Credit will be acceptable. \n \nCollateral Call: \n \n“Collateral Call” shall mean a notice to a Participant that additional Collateral, or possibly early \npayment, is required in order to remain in, or to regain, compliance with Tariff, Attachment Q. \n \nCo-Located Resource: \n \n“Co-Located Resource” shall mean a component of a Mixed Technology Facility that operates in \nthe capacity, energy, and/or ancillary services market(s) as a separate resource from the other \ncomponents of such facility. \n \nCommencement Date: \n \n“Commencement Date” shall mean the date on which Interconnection Service commences in \naccordance with an Interconnection Service Agreement. \n \nCommitted Offer: \n \nThe “Committed Offer” shall mean 1) for pool-scheduled resources, an offer on which a resource \nwas scheduled by the Office of the Interconnection for a particular clock hour for an Operating \nDay, and 2) for self-scheduled resources, either the offer on which the Market Seller has elected \nto schedule the resource or the applicable offer for the resource determined pursuant to Operating \nAgreement, Schedule 1, section 6.4, and the parallel provisions of Tariff, Attachment K-\nAppendix, section 6.4, or Operating Agreement, Schedule 1, section 6.6, and the parallel \nprovisions of Tariff, Attachment K-Appendix, section 6.6, for a particular clock hour for an \nOperating Day."},{"page":7,"startToken":1801,"endToken":2191,"text":"Completed Application: \n \n“Completed Application” shall mean an application that satisfies all of the information and other \nrequirements of the Tariff, including any required deposit. \n \nCompliance Aggregation Area (CAA): \n \n“Compliance Aggregation Area” or “CAA” shall mean a geographic area of Zones or sub-Zones \nthat are electrically-contiguous and experience for the relevant Delivery Year, based on Resource \nClearing Prices of, for Delivery Years through May 31, 2018, Annual Resources and for the \n2018/2019 Delivery Year and subsequent Delivery Years, Capacity Performance Resources, the \nsame locational price separation in the Base Residual Auction, the same locational price \nseparation in the First Incremental Auction, the same locational price separation in the Second \nIncremental Auction, the same locational price separation in the Third Incremental Auction. \n \nComponent DER: \n \n“Component DER” shall mean any resource, within the PJM Region, that is located on a \ndistribution system, any subsystem thereof, or behind a customer meter, and is used in a DER \nAggregation Resource by a DER Aggregator to participate in the energy, capacity, and/or \nancillary services markets of PJM through the DER Aggregator Participation Model.  A \nComponent DER may not exceed 5 MW.   \n \nComposite Energy Offer:  \n \n“Composite Energy Offer” for generation resources shall mean the sum (in $/MWh) of the \nIncremental Energy Offer and amortized Start-Up Costs and amortized No-load Costs, and for \nEconomic Load Response Participant resources the sum (in $/MWh) of the Incremental Energy \nOffer and amortized shutdown costs, as determined in accordance with Tariff, Attachment K-\nAppendix, section 2.4 and Tariff, Attachment K-Appendix, section 2.4A and the PJM Manuals. \n \nConditional Incremental Auction: \n \n“Conditional Incremental Auction” shall mean an Incremental Auction conducted for a Delivery \nYear if and when necessary to secure commitments of additional capacity to address reliability \ncriteria violations arising from the delay in a Backbone Transmission upgrade that was modeled \nin the Base Residual Auction for such Delivery Year. \n \nConditioned State Support: \n \n“Conditioned State Support” shall mean any financial benefit required or incentivized by a state, \nor political subdivision of a state acting in its sovereign capacity, that is provided outside of PJM \nMarkets and in exchange for the sale of a FERC-jurisdictional product conditioned on clearing in \nany RPM Auction, where “conditioned on clearing in any RPM Auction” refers to specific \ndirectives as to the level of the offer that must be entered for the relevant Generation Capacity"},{"page":8,"startToken":2191,"endToken":2565,"text":"Resource in the RPM Auction or directives that the Generation Capacity Resource is required to \nclear in any RPM Auction.  Conditioned State Support shall not include any Legacy Policy.   \n \nCONE Area: \n \n“CONE Area” shall mean the areas listed in Tariff, Attachment DD, section 5.10(a)(iv)(A) and \nany LDAs established as CONE Areas pursuant to Tariff, Attachment DD, section \n5.10(a)(iv)(B).  \n \nConfidential Information: \n \n“Confidential Information” shall mean any confidential, proprietary, or trade secret information \nof a plan, specification, pattern, procedure, design, device, list, concept, policy, or compilation \nrelating to the present or planned business of a New Service Customer, Transmission Owner, or \nother Interconnection Party or Construction Party, which is designated as confidential by the \nparty supplying the information, whether conveyed verbally, electronically, in writing, through \ninspection, or otherwise, and shall include, without limitation, all information relating to the \nproducing party’s technology, research and development, business affairs and pricing, and any \ninformation supplied by any New Service Customer, Transmission Owner, or other \nInterconnection Party or Construction Party to another such party prior to the execution of an \nInterconnection Service Agreement or a Construction Service Agreement. \n \nCongestion Price: \n \n“Congestion Price” shall mean the congestion component of the Locational Marginal Price, \nwhich is the effect on transmission congestion costs (whether positive or negative) associated \nwith increasing the output of a generation resource or decreasing the consumption by a Demand \nResource, based on the effect of increased generation from or consumption by the resource on \ntransmission line loadings, calculated as specified in Operating Agreement, Schedule 1, section \n2, and the parallel provisions of Tariff, Attachment K-Appendix. \n \nConsolidated Transmission Owners Agreement, PJM Transmission Owners Agreement or \nTransmission Owners Agreement: \n \n“Consolidated Transmission Owners Agreement,” “PJM Transmission Owners Agreement” or \n“Transmission Owners Agreement” shall mean the certain Consolidated Transmission Owners \nAgreement dated as of December 15, 2005, by and among the Transmission Owners and by and \nbetween the Transmission Owners and PJM Interconnection, L.L.C. on file with the \nCommission, as amended from time to time. \n \nConstraint Relaxation Logic:  \n \n“Constraint Relaxation Logic” shall mean the logic applied in the market clearing software \nwhere the transmission limit is increased to prevent the Transmission Constraint Penalty Factor \nfrom setting the Marginal Value of a transmission constraint."},{"page":9,"startToken":2565,"endToken":2876,"text":"Constructing Entity: \n \n“Constructing Entity” shall mean either the Transmission Owner or the New Services Customer, \ndepending on which entity has the construction responsibility pursuant to Tariff, Part VI and the \napplicable Construction Service Agreement; this term shall also be used to refer to an \nInterconnection Customer with respect to the construction of the Customer Interconnection \nFacilities. \n \nConstruction Party: \n \n“Construction Party” shall mean a party to a Construction Service Agreement.  “Construction \nParties” shall mean all of the Parties to a Construction Service Agreement. \n \nConstruction Service Agreement: \n \n“Construction Service Agreement” shall mean either an Interconnection Construction Service \nAgreement or an Upgrade Construction Service Agreement. \n \nContingent Facilities: \n \n“Contingent Facilities” shall mean those unbuilt Interconnection Facilities and Network \nUpgrades upon which the Interconnection Request’s costs, timing, and study findings are \ndependent and, if delayed or not built, could cause a need for restudies of the Interconnection \nRequest or a reassessment of the Interconnection Facilities and/or Network Upgrades and/or \ncosts and timing. \n \nContinuous Mode: \n \n“Continuous Mode” shall mean the mode of operation of an Energy Storage Resource Model \nParticipant or Open-Loop Hybrid Resource that includes both negative and positive megawatt \nquantities (i.e., the Energy Storage Resource Model Participant or Open-Loop Hybrid Resource \nis capable of continually and immediately transitioning from withdrawing megawatt quantities \nfrom the grid to injecting megawatt quantities onto the grid or injecting megawatts to \nwithdrawing megawatts).  Energy Storage Resource Model Participants or Open-Loop Hybrid \nResource operating in Continuous Mode are considered to have an unlimited ramp rate.  \nContinuous Mode requires Discharge Economic Maximum Megawatts to be zero or correspond \nto an injection, and Charge Economic Maximum Megawatts to be zero or correspond to a \nwithdrawal. \n \nControl Area: \n \n“Control Area” shall mean an electric power system or combination of electric power systems \nbounded by interconnection metering and telemetry to which a common automatic generation \ncontrol scheme is applied in order to:"},{"page":10,"startToken":2876,"endToken":3173,"text":"(1) \nmatch the power output of the generators within the electric power system(s) and \nenergy purchased from entities outside the electric power system(s), with the load within the \nelectric power system(s); \n \n \n(2) \nmaintain scheduled interchange with other Control Areas, within the limits of \nGood Utility Practice; \n \n \n(3) \nmaintain the frequency of the electric power system(s) within reasonable limits in \naccordance with Good Utility Practice; and \n \n \n(4) \nprovide sufficient generating capacity to maintain operating reserves in \naccordance with Good Utility Practice. \n \nControl Zone: \n \n“Control Zone” shall have the meaning given in the Operating Agreement. \n \nControllable A.C. Merchant Transmission Facilities: \n \n“Controllable A.C. Merchant Transmission Facilities” shall mean transmission facilities that (1) \nemploy technology which Transmission Provider reviews and verifies will permit control of \nthe amount and/or direction of power flow on such facilities to such extent as to effectively \nenable the controllable facilities to be operated as if they were direct current transmission \nfacilities, and (2) that are interconnected with the Transmission System pursuant to Tariff, Part \nIV and Part VI. \n \nCoordinated External Transaction: \n \n“Coordinated External Transaction” shall mean a transaction to simultaneously purchase and sell \nenergy on either side of a CTS Enabled Interface in accordance with the procedures of Operating \nAgreement, Schedule 1, section 1.13, and the parallel provisions of Tariff, Attachment K-\nAppendix. \n \nCoordinated Transaction Scheduling: \n \n“Coordinated Transaction Scheduling” or “CTS” shall mean the scheduling of Coordinated \nExternal Transactions at a CTS Enabled Interface in accordance with the procedures of \nOperating Agreement, Schedule 1, section 1.13, and the parallel provisions of Tariff, Attachment \nK-Appendix. \n \nCorporate Guaranty: \n \n“Corporate Guaranty” shall mean a legal document, in a form acceptable to PJM and/or \nPJMSettlement, used by a Credit Affiliate of an entity to guaranty the obligations of another \nentity."},{"page":11,"startToken":3173,"endToken":3554,"text":"Cost of New Entry: \n \n“Cost of New Entry” or “CONE” shall mean the nominal levelized cost of a Reference Resource, \nas determined in accordance with Tariff, Attachment DD, section 5. \n \nCosts: \n \nAs used in Tariff, Part IV, Part VI and related attachments, “Costs” shall mean costs and \nexpenses, as estimated or calculated, as applicable, including, but not limited to, capital \nexpenditures, if applicable, and overhead, return, and the costs of financing and taxes and any \nIncidental Expenses. \n \nCounterparty:  \n \n“Counterparty” shall mean PJMSettlement as the contracting party, in its name and own right \nand not as an agent, to an agreement or transaction with a Market Participant or other entities, \nincluding the agreements and transactions with customers regarding transmission service and \nother transactions under the PJM Tariff and the Operating Agreement.  PJMSettlement shall not \nbe a counterparty to (i) any bilateral transactions between Members, or (ii) any Member’s self-\nsupply of energy to serve its load, or (iii) any Member’s self-schedule of energy reported to the \nOffice of the Interconnection to the extent that energy serves that Member’s own load. \n \nCredit Affiliate: \n \n“Credit Affiliate” shall mean Principals, corporations, partnerships, firms, joint ventures, \nassociations, joint stock companies, trusts, unincorporated organizations or entities, one of which \ndirectly or indirectly controls the other or that are both under common Control. “Control,” as that \nterm is used in this definition, shall mean the possession, directly or indirectly, of the power to \ndirect the management or policies of a person or an entity. \n \nCredit Available for Export Transactions: \n \n“Credit Available for Export Transactions” shall mean a designation of credit to be used for \nExport Transactions that is allocated by each Market Participant from its Credit Available for \nVirtual Transactions, and which reduces the Market Participant's Credit Available for Virtual \nTransactions accordingly. \n \nCredit Available for Virtual Transactions: \n \n“Credit Available for Virtual Transactions” shall mean the Market Participant’s Working Credit \nLimit for Virtual Transactions calculated on its credit provided in compliance with its Peak \nMarket Activity requirement plus available credit submitted above that amount, less any unpaid \nbilled and unbilled amounts owed to PJMSettlement, plus any unpaid unbilled amounts owed by \nPJMSettlement to the Market Participant, less any applicable credit required for Minimum \nParticipation Requirements, FTRs, RPM activity,  or other credit requirement determinants as \ndefined in Tariff, Attachment Q."},{"page":12,"startToken":3554,"endToken":4000,"text":"Credit Breach: \n \n“Credit Breach” shall mean (a) the failure of a Participant to perform, observe, meet or comply \nwith any requirements of Tariff, Attachment Q or other provisions of the Agreements, other than \na Financial Default, or (b) a determination by PJM and notice to the Participant that a Participant \nrepresents an unreasonable credit risk to the PJM Markets; that, in either event, has not been \ncured or remedied after any required notice has been given and any cure period has elapsed. \n \nCredit-Limited Offer: \n \n“Credit-Limited Offer” shall mean a Sell Offer that is submitted by a Market Participant in an \nRPM Auction subject to a maximum credit requirement specified by such Market Participant. \n \nCredit Support Default: \n \n“Credit Support Default,” shall mean (a) the failure of any Guarantor of a Market Participant to \nmake any payment, or to perform, observe, meet or comply with any provisions of the applicable \nGuaranty or Credit Support Document that has not been cured or remedied, after any required \nnotice has been given and an opportunity to cure (if any) has elapsed, (b) a representation made \nor deemed made by a Guarantor in any Credit Support Document that proves to be false, \nincorrect or misleading in any material respect when made or deemed made, (c) the failure of a \nGuaranty or other Credit Support Document to be in full force and effect prior to the satisfaction \nof all obligations of such Participant to PJM, without PJM’s consent, or (d) a Guarantor \nrepudiating, disaffirming, disclaiming or rejecting, in whole or in part, its obligations under the \nGuaranty or challenging the validity of the Guaranty.  \n \nCredit Support Document:  \n \n“Credit Support Document” shall mean any agreement or instrument in any way guaranteeing or \nsecuring any or all of a Participant’s obligations under the Agreements (including, without \nlimitation, the provisions of Tariff, Attachment Q), any agreement entered into under, pursuant \nto, or in connection with the Agreements or any agreement entered into under, pursuant to, or in \nconnection with the Agreements and/or any other agreement to which PJM, PJMSettlement and \nthe Participant are parties, including, without limitation, any Corporate Guaranty, Letter of \nCredit, or agreement granting PJM and PJMSettlement a security interest. \n \nCritical Natural Gas Infrastructure:  \n \n“Critical Natural Gas Infrastructure” shall mean locations with electrical loads that are involved \nin natural gas production, processing, intrastate and interstate transmission and distribution \npipeline facility as defined by NERC/FERC standard(s); and until such NERC/FERC standard(s) \nis developed, is defined as electric loads that are involved in natural gas production, processing, \nintrastate and interstate transmission and distribution pipeline facility, which if curtailed, will \nimpact the delivery of natural gas to bulk-power system natural gas-fired generation."},{"page":13,"startToken":4000,"endToken":4342,"text":"Cross-Border: \n \nWhen used to describe Network Integration Transmission Service, Network External Designated \nTransmission Service or Point-to-Point Transmission Service, “Cross-Border” shall mean \ntransmission service where the capacity and/or energy is delivered from a resource that is not \npart of the PJM Transmission System and/or to load that is not part of the PJM Transmission \nSystem. \n \nCTS Enabled Interface: \n \n“CTS Enabled Interface” shall mean an interface between the PJM Control Area and an adjacent \nControl Area at which the Office of the Interconnection has authorized the use of Coordinated \nTransaction Scheduling (“CTS”). The CTS Enabled Interfaces between the PJM Control Area \nand the New York Independent System Operator, Inc. Control Area shall be designated in \nSchedule A to the Joint Operating Agreement Among and Between New York Independent \nSystem Operator Inc. and PJM Interconnection, L.L.C. (PJM Rate Schedule FERC No. 45).  The \nCTS Enabled Interfaces between the PJM Control Area and the Midcontinent Independent \nSystem Operator, Inc. shall be designated consistent with Attachment 3, section 2 of the Joint \nOperating Agreement between Midcontinent Independent System Operator, Inc. and PJM \nInterconnection, L.L.C. \n \nCTS Interface Bid: \n \n“CTS Interface Bid” shall mean a unified real-time bid to simultaneously purchase and sell \nenergy on either side of a CTS Enabled Interface in accordance with the procedures of Operating \nAgreement, Schedule 1, section 1.13, and the parallel provisions of Tariff, Attachment K-\nAppendix. \n \nCurtailment: \n \n“Curtailment” shall mean a reduction in firm or non-firm transmission service in response to a \ntransfer capability shortage as a result of system reliability conditions. \n \nCurtailment Service Provider: \n \n“Curtailment Service Provider” or “CSP” shall mean a Member or a Special Member, which \naction on behalf of itself or one or more other Members or non-Members, participates in the PJM \nInterchange Energy Market, Ancillary Services markets, and/or Reliability Pricing Model by \ncausing a reduction in demand. \n \nCustomer Facility: \n \n“Customer Facility” shall mean Generation Facilities or Merchant Transmission Facilities \ninterconnected with or added to the Transmission System pursuant to an Interconnection Request \nunder Subparts A of Tariff, Part IV."},{"page":14,"startToken":4342,"endToken":4666,"text":"Customer-Funded Upgrade: \n \n“Customer-Funded Upgrade” shall mean any Network Upgrade, Local Upgrade, or Merchant \nNetwork Upgrade for which cost responsibility (i) is imposed on an Interconnection Customer or \nan Eligible Customer pursuant to Tariff, Part VI, section 217, or (ii) is voluntarily undertaken by \na New Service Customer in fulfillment of an Upgrade Request.  No Network Upgrade, Local \nUpgrade or Merchant Network Upgrade or other transmission expansion or enhancement shall be \na Customer-Funded Upgrade if and to the extent that the costs thereof are included in the rate \nbase of a public utility on which a regulated return is earned. \n \nCustomer Interconnection Facilities: \n \n“Customer Interconnection Facilities” shall mean all facilities and equipment owned and/or \ncontrolled, operated and maintained by Interconnection Customer on Interconnection Customer’s \nside of the Point of Interconnection identified in the appropriate appendices to the \nInterconnection Service Agreement and to the Interconnection Construction Service Agreement, \nincluding any modifications, additions, or upgrades made to such facilities and equipment, that \nare necessary to physically and electrically interconnect the Customer Facility with the \nTransmission System. \n \nDaily Deficiency Rate: \n \n“Daily Deficiency Rate” shall mean the rate employed to assess certain deficiency charges as \ndetailed under Tariff, Attachment DD, section 7. \n \nDaily Unforced Capacity Obligation: \n \n“Daily Unforced Capacity Obligation” shall mean the capacity obligation of a Load Serving \nEntity during the Delivery Year, determined in accordance with  Reliability Assurance \nAgreement, Schedule 8, or, as to an FRR entity, in Reliability Assurance Agreement, Schedule \n8.1. \n \nDay-ahead Congestion Price: \n \n“Day-ahead Congestion Price” shall mean the Congestion Price resulting from the Day-ahead \nEnergy Market. \n \nDay-ahead Energy Market: \n \n“Day-ahead Energy Market” shall mean the schedule of commitments for the purchase or sale of \nenergy and payment of Transmission Congestion Charges developed by the Office of the \nInterconnection as a result of the offers and specifications submitted in accordance with \nOperating Agreement, Schedule 1, section 1.10 and the parallel provisions of Tariff, Attachment \nK-Appendix. \n \nDay-ahead Energy Market Injection Congestion Credits:"},{"page":15,"startToken":4666,"endToken":4960,"text":"“Day-ahead Energy Market Injection Congestion Credits” shall mean those congestion credits \npaid to Market Participants for supply transactions in the Day-ahead Energy Market including \ngeneration schedules, Increment Offers, Up-to Congestion Transactions, import transactions, and \nDay-Ahead Pseudo-Tie Transactions. \n \nDay-ahead Energy Market Transmission Congestion Charges: \n \n“Day-ahead Energy Market Transmission Congestion Charges” shall be equal to the sum of Day-\nahead Energy Market Withdrawal Congestion Charges minus [the sum of Day-ahead Energy \nMarket Injection Congestion Credits plus any congestion charges calculated pursuant to the Joint \nOperating Agreement between the Midcontinent Independent Transmission System Operator, \nInc. and PJM Interconnection, L.L.C. (PJM Rate Schedule FERC No. 38), plus any congestion \ncharges calculated pursuant to the Joint Operating Agreement Among and Between New York \nIndependent System Operator Inc. and PJM Interconnection, L.L.C. (PJM Rate Schedule FERC \nNo. 45), plus any congestion charges calculated pursuant to agreements between the Office of \nthe Interconnection and other entities, as applicable)]. \n \nDay-ahead Energy Market Withdrawal Congestion Charges: \n \n“Day-ahead Energy Market Withdrawal Congestion Charges” shall mean those congestion \ncharges collected from Market Participants for withdrawal transactions in the Day-ahead Energy \nMarket from transactions including Demand Bids, Decrement Bids, Up-to Congestion \nTransactions, Export Transactions, and Day-Ahead Pseudo-Tie Transactions. \n \nDay-ahead Loss Price: \n \n“Day-ahead Loss Price” shall mean the Loss Price resulting from the Day-ahead Energy Market. \n \nDay-ahead Prices: \n \n“Day-ahead Prices” shall mean the Locational Marginal Prices resulting from the Day-ahead \nEnergy Market. \n \nDay-Ahead Pseudo-Tie Transaction:  \n \n“Day-Ahead Pseudo-Tie Transaction” shall mean a transaction scheduled in the Day-ahead \nEnergy Market to the PJM-MISO interface from a generator within the PJM balancing authority \narea that Pseudo-Ties into the MISO balancing authority area. \n \nDay-ahead Settlement Interval:  \n \n“Day-ahead Settlement Interval” shall mean the interval used by settlements, which shall be \nevery one clock hour.  \n \nDay-ahead State of Charge:"},{"page":16,"startToken":4960,"endToken":5212,"text":"“Day-ahead State of Charge” shall mean the prospective State of Charge of an Energy Storage \nResource Model Participant as offered into the Day-ahead Energy Market according to the \nprocedures described in the PJM Manuals, measured in units of megawatt-hours. Day-ahead \nState of Charge for an interval represents the State of Charge at the beginning of that interval. \n \nDay-ahead System Energy Price: \n \n“Day-ahead System Energy Price” shall mean the System Energy Price resulting from the Day-\nahead Energy Market. \n \nDeactivation: \n \n“Deactivation” shall mean the retirement or mothballing of a generating unit governed by Tariff, \nPart V. \n \nDeactivation Avoidable Cost Credit: \n \n“Deactivation Avoidable Cost Credit” shall mean the credit paid to Generation Owners pursuant \nto Tariff, Part V, section 114. \n \nDeactivation Avoidable Cost Rate: \n \n“Deactivation Avoidable Cost Rate” shall mean the formula rate established pursuant to Tariff, \nPart V, section 115 of this Tariff. \n \nDeactivation Date: \n \n“Deactivation Date” shall mean the date a generating unit within the PJM Region is either retired \nor mothballed and ceases to operate. \n \nDecrement Bid: \n \n“Decrement Bid” shall mean a type of Virtual Transaction that is a bid to purchase energy at a \nspecified location in the Day-ahead Energy Market.  A cleared Decrement Bid results in \nscheduled load at the specified location in the Day-ahead Energy Market. \n \nDefault: \n \nAs used in the Interconnection Service Agreement and Construction Service Agreement, \n“Default” shall mean the failure of a Breaching Party to cure its Breach in accordance with the \napplicable provisions of an Interconnection Service Agreement or Construction Service \nAgreement. \n \nDelivering Party:"},{"page":17,"startToken":5212,"endToken":5565,"text":"“Delivering Party” shall mean the entity supplying capacity and energy to be transmitted at \nPoint(s) of Receipt. \n \nDelivery Year: \n \n“Delivery Year” shall mean the Planning Period for which a Capacity Resource is committed \npursuant to the auction procedures specified in Tariff, Attachment DD, or pursuant to an FRR \nCapacity Plan under Reliability Assurance Agreement, Schedule 8.1. \n \nDemand Bid: \n \n“Demand Bid” shall mean a bid, submitted by a Load Serving Entity in the Day-ahead Energy \nMarket, to purchase energy at its contracted load location, for a specified timeframe and \nmegawatt quantity, that if cleared will result in energy being scheduled at the specified location \nin the Day-ahead Energy Market and in the physical transfer of energy during the relevant \nOperating Day.   \n \nDemand Bid Limit: \n \n“Demand Bid Limit” shall mean the largest MW volume of Demand Bids that may be submitted \nby a Load Serving Entity for any hour of an Operating Day, as determined pursuant to Operating \nAgreement, Schedule 1, section 1.10.1B, and the parallel provisions of Tariff, Attachment K-\nAppendix. \n \nDemand Bid Screening: \n \n“Demand Bid Screening” shall mean the process by which Demand Bids are reviewed against \nthe applicable Demand Bid Limit, and rejected if they would exceed that limit, as determined \npursuant to Operating Agreement, Schedule 1, section 1.10.1B, and the parallel provisions of \nTariff, Attachment K-Appendix. \n \nDER Aggregation Resource: \n \n“DER Aggregation Resource” shall be comprised of one or more Component DER.  A DER \nAggregation Resource is used by a DER Aggregator to participate: (1) in the energy, capacity, \nand/or ancillary services markets of PJM; or (2) in the Reliability Backstop Procurement as an \nRBP Resource to the extent the DER Aggregation Resource meets the requirements set forth in \nTariff, Attachment, DD, section 18.5(d), through the DER Aggregator Participation Model.  A \nDER Aggregation Resource is capable of satisfying a minimum energy and/or ancillary services \nmarket offer of 100 kW.  The market participation eligibility of a DER Aggregation Resource \nshall be determined in accordance with the physical and operational characteristics of the \nunderlying Component DER that comprise the DER Aggregation Resource. \n \nDER Aggregator:"},{"page":18,"startToken":5565,"endToken":5874,"text":"“DER Aggregator” shall mean an entity that is a Market Participant that: (i) uses one or more \nDER Aggregation Resources to participate in the energy, capacity, and/or ancillary services \nmarkets of PJM through the DER Aggregator Participation Model; and (ii) has a fully-executed \nDER Aggregator Participation Service Agreement. \n \nDER Aggregator Participation Model: \n \n“DER Aggregator Participation Model” shall mean the participation model described in Tariff, \nAttachment K-Appendix, section 1.4B. \n \nDER Capacity Aggregation Resource: \n \n“DER Capacity Aggregation Resource” shall mean one or more DER Aggregation Resource that \nparticipates in the Reliability Pricing Model, capable of satisfying a minimum capacity market \noffer of 100 kW, or is otherwise treated as capacity in PJM’s markets, such as through a Fixed \nResource Requirement Capacity Plan, for the 2028/2029 Delivery Year and all subsequent \nDelivery Years.   \n \nDesignated Agent: \n \n“Designated Agent” shall mean any entity that performs actions or functions on behalf of the \nTransmission Provider, a Transmission Owner, an Eligible Customer, or the Transmission \nCustomer required under the Tariff. \n \nDesignated Entity: \n \n“Designated Entity” shall have the same meaning provided in the Operating Agreement. \n \nDirect Assignment Facilities: \n \n“Direct Assignment Facilities” shall mean facilities or portions of facilities that are constructed \nfor the sole use/benefit of a particular Transmission Customer requesting service under the \nTariff.  Direct Assignment Facilities shall be specified in the Service Agreement that governs \nservice to the Transmission Customer and shall be subject to Commission approval. \n \nDirect Charging Energy: \n \n“Direct Charging Energy” shall mean the energy that an Energy Storage Resource or Open-Loop \nHybrid Resource purchases from the PJM Interchange Energy Market and (i) later resells to the \nPJM Interchange Energy Market; or (ii) is lost to conversion inefficiencies, provided that such \ninefficiencies are an unavoidable component of the conversion, storage, and discharge process \nthat is used to resell energy back to the PJM Interchange Energy Market. \n \nDirect Load Control:"},{"page":19,"startToken":5874,"endToken":6199,"text":"“Direct Load Control” shall mean load reduction that is controlled directly by the Curtailment \nService Provider’s market operations center or its agent, in response to PJM instructions. \n \nDischarge Economic Maximum Megawatts: \n \n“Discharge Economic Maximum Megawatts” shall mean the maximum megawatt power output \navailable for discharge in economic dispatch by an Energy Storage Resource Model Participant \nor Open-Loop Hybrid Resource in Continuous Mode or in Discharge Mode. Discharge \nEconomic Maximum Megawatts shall be the Economic Maximum for an Energy Storage \nResource or Open-Loop Hybrid Resource in Discharge Mode or in Continuous Mode. \n \nDischarge Economic Minimum Megawatts: \n \n“Discharge Economic Minimum Megawatts” shall mean the minimum megawatt power output \navailable for discharge in economic dispatch by an Energy Storage Resource Model Participant \nor Open-Loop Hybrid Resource in Discharge Mode.  Discharge Economic Minimum Megawatts \nshall be the Economic Minimum for an Energy Storage Resource or Open-Loop Hybrid \nResource in Discharge Mode. \n \nDischarge Mode: \n \n“Discharge Mode” shall mean the mode of operation of an Energy Storage Resource Model \nParticipant or Open-Loop Hybrid Resource that only includes positive megawatt quantities (i.e., \nthe Energy Storage Resource Model Participant or Open-Loop Hybrid Resource is only injecting \nmegawatts onto the grid).   \n \nDischarge Ramp Rate: \n \n“Discharge Ramp Rate” shall mean the Ramping Capability of an Energy Storage Resource \nModel Participant or Open-Loop Hybrid Resource in Discharge Mode. \n \nDispatch Rate: \n \n“Dispatch Rate” shall mean the control signal, expressed in dollars per megawatt-hour, \ncalculated and transmitted continuously and dynamically to direct the output level of all \ngeneration resources dispatched by the Office of the Interconnection in accordance with the \nOffer Data. \n \nDispatched Charging Energy:   \n \n“Dispatched Charging Energy” shall mean Direct Charging Energy that an Energy Storage \nResource Model Participant or Open-Loop Hybrid Resource receives from the electric grid \npursuant to PJM dispatch while providing one of the following services in the PJM markets: \nEnergy Imbalance Service pursuant to Tariff, Schedule 4; Regulation; Tier 2 Synchronized \nReserves; or Reactive Service.  Energy Storage Resource Model Participants and Open-Loop"},{"page":20,"startToken":6199,"endToken":6246,"text":"Hybrid Resource shall be considered to be providing Energy Imbalance Service when they are \ndispatchable by PJM in real-time.   \n \nDynamic Schedule: \n \n“Dynamic Schedule” shall have the same meaning provided in the Operating Agreement. \n \nDynamic Transfer: \n \n“Dynamic Transfer” shall have the same meaning provided in the Operating Agreement."},{"page":21,"startToken":6246,"endToken":6555,"text":"Definitions – E - F \n \nEconomic-based Enhancement or Expansion: \n \n“Economic-based Enhancement or Expansion” shall have the same meaning provided in the \nOperating Agreement. \n \nEconomic Load Response Participant: \n \n“Economic Load Response Participant” shall mean a Member or Special Member that qualifies \nunder Operating Agreement, Schedule 1, section 1.5A, and the parallel provisions of Tariff, \nAttachment K-Appendix, section 1.5A, to participate in the PJM Interchange Energy Market \nand/or Ancillary Services markets through reductions in demand. \n \nEconomic Load Response Regulation Only Participant:  \n \n“Economic Load Response Regulation Only Participant” shall mean a Member or Special \nMember that qualifies under Operating Agreement, Schedule 1, section 1.5A, and the parallel \nprovisions of Tariff, Attachment K-Appendix, section 1.5A, and is only eligible to participate in \nthe PJM Regulation market. \n \nEconomic Maximum: \n \n“Economic Maximum” shall mean the highest incremental MW output level, submitted to PJM \nmarket systems by a Market Participant, that a unit can achieve while following economic \ndispatch.   \n \nEconomic Minimum: \n \n“Economic Minimum” shall mean the lowest incremental MW output level, submitted to PJM \nmarket systems by a Market Participant, that a unit can achieve while following economic \ndispatch. \n \nEffective FTR Holder: \n \n“Effective FTR Holder” shall mean: \n \n(i) For an FTR Holder that is either a (a) privately held company, or (b) a municipality or \nelectric cooperative, as defined in the Federal Power Act, such FTR Holder, together with \nany Affiliate, subsidiary or parent of the FTR Holder, any other entity that is under common \nownership, wholly or partly, directly or indirectly, or has the ability to influence, directly or \nindirectly, the management or policies of the FTR Holder; or  \n \n(ii) For an FTR Holder that is a publicly traded company including a wholly owned \nsubsidiary of a publicly traded company, such FTR Holder, together with any Affiliate, \nsubsidiary or parent of the FTR Holder, any other PJM Member has over 10% common"},{"page":22,"startToken":6555,"endToken":6914,"text":"ownership with the FTR Holder, wholly or partly, directly or indirectly, or has the ability to \ninfluence, directly or indirectly, the management or policies of the FTR Holder; or  \n \n(iii)  an FTR Holder together with any other PJM Member, including also any Affiliate, \nsubsidiary or parent of such other PJM Member, with which it shares common ownership, \nwholly or partly, directly or indirectly, in any third entity which is a PJM Member (e.g., a \njoint venture). \n \n \nEFORd: \n \n“EFORd” shall have the meaning specified in the PJM Reliability Assurance Agreement. \n \nElectrical Distance: \n \n“Electrical Distance” shall mean, for a Generation Capacity Resource geographically located \noutside the metered boundaries of the PJM Region, the measure of distance, based on impedance \nand in accordance with the PJM Manuals, from the Generation Capacity Resource to the PJM \nRegion. \n \nEligible Customer: \n \n“Eligible Customer” shall mean: \n \n(i) Any electric utility (including any Transmission Owner and any power marketer), Federal \npower marketing agency, or any person generating electric energy for sale for resale is an \nEligible Customer under the Tariff.  Electric energy sold or produced by such entity may be \nelectric energy produced in the United States, Canada or Mexico.  However, with respect to \ntransmission service that the Commission is prohibited from ordering by Section 212(h) of the \nFederal Power Act, such entity is eligible only if the service is provided pursuant to a state \nrequirement that the Transmission Provider or Transmission Owner offer the unbundled \ntransmission service, or pursuant to a voluntary offer of such service by a Transmission Owner. \n \n(ii) Any retail customer taking unbundled transmission service pursuant to a state requirement \nthat the Transmission Provider or a Transmission Owner offer the transmission service, or \npursuant to a voluntary offer of such service by a Transmission Owner, is an Eligible Customer \nunder the Tariff.  As used in Tariff, Part VI, Eligible Customer shall mean only those Eligible \nCustomers that have submitted a Completed Application. \n \nEligible Fast-Start Resource: \n \n“Eligible Fast-Start Resource” shall mean a Fast-Start Resource that is eligible for the \napplication of Integer Relaxation during the calculation of Locational Marginal Prices as set \nforth in Tariff, Attachment K-Appendix, section 2.2. \n \nEmergency Action:"},{"page":23,"startToken":6914,"endToken":7359,"text":"“Emergency Action” shall mean (1) any megawatt shortage of the Primary Reserve Requirement \n(as specified in the PJM Manuals) in a Reserve Zone or Reserve Sub-zone, inclusive of any \nadjustments to such requirement to account for system conditions, as determined by the dispatch \nrun from the security constrained economic dispatch and where, as specified in the PJM \nManuals, there is also a Voltage Reduction Warning and reduction of non-critical plant load, \nManual Load Dump Warning, Maximum Generation Emergency Action, or the curtailment of \nnon-essential building loads and Voltage Reduction Warning that encompasses such Reserve \nZone or Reserve Sub-zone or (2) anytime the Office of Interconnection identifies an emergency \nand issues a load shed directive, Manual Load Dump Action, Voltage Reduction Action, or \ndeploy all resources action for an entire Reserve Zone or Reserve Sub-zone. \n \nEmergency Condition: \n \n“Emergency Condition” shall mean a condition or situation (i) that in the judgment of any \nInterconnection Party is imminently likely to endanger life or property; or (ii) that in the \njudgment of the Interconnected Transmission Owner or Transmission Provider is imminently \nlikely (as determined in a non-discriminatory manner) to cause a material adverse effect on the \nsecurity of, or damage to, the Transmission System, the Interconnection Facilities, or the \ntransmission systems or distribution systems to which the Transmission System is directly or \nindirectly connected; or (iii) that in the judgment of Interconnection Customer is imminently \nlikely (as determined in a non-discriminatory manner) to cause damage to the Customer Facility \nor to the Customer Interconnection Facilities.  System restoration and black start shall be \nconsidered Emergency Conditions, provided that a Generation Interconnection Customer is not \nobligated by an Interconnection Service Agreement to possess black start capability.  Any \ncondition or situation that results from lack of sufficient generating capacity to meet load \nrequirements or that results solely from economic conditions shall not constitute an Emergency \nCondition, unless one or more of the enumerated conditions or situations identified in this \ndefinition also exists. \n \nEmergency Load Response Program: \n“Emergency Load Response Program” shall mean the program by which Curtailment Service \nProviders may be compensated by PJM for Demand Resources that will reduce load when \ndispatched by PJM during emergency conditions, and is described in Operating Agreement, \nSchedule 1, section 8  and the parallel provisions of Tariff, Attachment K-Appendix, section 8.  \n \nEnergy Efficiency Resource: \n \n“Energy Efficiency Resource” shall have the meaning specified in the PJM Reliability Assurance \nAgreement. \n \nEnergy Market Opportunity Cost: \n \n“Energy Market Opportunity Cost” shall mean the difference between (a) the forecasted cost to \noperate a specific generating unit when the unit only has an operational limitation due to \nlimitations imposed on the unit by Applicable Laws and Regulations, and (b) the forecasted"},{"page":24,"startToken":7359,"endToken":7698,"text":"future Locational Marginal Price at which the generating unit could run while not violating such \nlimitations.  Energy Market Opportunity Cost therefore is the value associated with a specific \ngenerating unit’s lost opportunity to produce energy during a higher valued period of time \noccurring within the same compliance period, which compliance period is determined by the \napplicable regulatory authority and is reflected in the rules set forth in PJM Manual 15.  Energy \nMarket Opportunity Costs shall be limited to those resources which are specifically delineated in \nOperating Agreement, Schedule 2. \n \nEnergy Resource: \n \n“Energy Resource” shall mean a Generating Facility that is not a Capacity Resource. \n \nEnergy Settlement Area: \n \n“Energy Settlement Area” shall mean the bus or distribution of busses that represents the \nphysical location of Network Load and by which the obligations of the Network Customer to \nPJM are settled. \n \nEnergy Storage Resource: \n \n“Energy Storage Resource” shall mean a resource capable of receiving electric energy from the \ngrid and storing it for later injection to the grid that (1) participates in the PJM Energy, Capacity \nand/or Ancillary Services markets as a Market Participant; or (2) may be an RBP Resource to the \nextent that the Energy Storage Resource meets the requirements set forth in Tariff, Attachment \nDD, section 18.5(b).  Open-Loop Hybrid Resources are not Energy Storage Resources. \n \nEnergy Storage Resource Model Participant:  \n \n“Energy Storage Resource Model Participant” shall mean an Energy Storage Resource utilizing \nthe Energy Storage Resource Participation Model.   \n \nEnergy Storage Resource Participation Model:  \n \n“Energy Storage Resource Participation Model” shall mean the participation model accepted by \nthe Commission in Docket No. ER19-469-000. \n \nEnergy Transmission Injection Rights: \n \n“Energy Transmission Injection Rights” shall mean the rights to schedule energy deliveries at a \nspecified point on the Transmission System. Energy Transmission Injection Rights may be \nawarded only to a Merchant D.C. Transmission Facility that connects the Transmission System \nto another control area. Deliveries scheduled using Energy Transmission Injection Rights have \nrights similar to those under Non-Firm Point-to-Point Transmission Service. \n \nEntity Providing Supply Services to Default Retail Service Provider:"},{"page":25,"startToken":7698,"endToken":8054,"text":"“Entity Providing Supply Services to Default Retail Service Provider” shall mean any entity, \nincluding but not limited to a load aggregator or power marketer, providing supply services to an \nelectric distribution company when that electric distribution company is serving as the default \nretail service provider, and that enters into a contract or similar obligation with such electric \ndistribution company to serve retail customers who have not selected a competitive retail service \nprovider.  \n \nEnvironmental Laws: \n \n“Environmental Laws” shall mean applicable Laws or Regulations relating to pollution or \nprotection of the environment, natural resources or human health and safety. \n \nEnvironmentally-Limited Resource: \n \n“Environmentally-Limited Resource” shall mean a resource which has a limit on its run hours \nimposed by a federal, state, or other governmental agency that will significantly limit its \navailability, on either a temporary or long-term basis. This includes a resource that is limited by a \ngovernmental authority to operating only during declared PJM capacity emergencies. \n \nEquivalent Load: \n \n“Equivalent Load” shall mean the sum of a Market Participant’s net system requirements to \nserve its customer load in the PJM Region, if any, plus its net bilateral transactions. \n \nEvent of Default: \n \n“Event of Default,” as that term is used in Tariff, Attachment Q, shall mean a Financial Default, \nCredit Breach, or Credit Support Default.   \n \nExercise of Buyer-Side Market Power: \n \n“Exercise of Buyer-Side Market Power” shall mean anti-competitive behavior of a Capacity \nMarket Seller with a Load Interest, or directed by an entity with a Load Interest, to \nuneconomically lower RPM Auction Sell Offer(s) in order to suppress RPM Auction clearing \nprices for the overall benefit of the Capacity Market Seller’s (and/or affiliates of Capacity \nMarket Seller) portfolio of generation and load or that of the directing entity with a Load Interest \nas determined pursuant to Tariff, Attachment DD, section 5.14(h-2)(2)(B). A bilateral contract \nbetween the Capacity Market Seller and an entity with a Load Interest with the express purpose \nof lowering capacity market clearing prices shall be evidence of the Exercise of Buyer-Side \nMarket Power. \n \nExisting Generation Capacity Resource: \n \n“Existing Generation Capacity Resource” shall have the meaning specified in the Reliability \nAssurance Agreement."},{"page":26,"startToken":8054,"endToken":8462,"text":"Export Credit Exposure: \n  \n“Export Credit Exposure” is determined for each Market Participant for a given Operating Day, \nand shall mean the sum of credit exposures for the Market Participant’s Export Transactions for \nthat Operating Day and for the preceding Operating Day. \n \nExport Nodal Reference Price: \n \n“Export Nodal Reference Price” at each location is the 97th percentile, shall be, the real-time \nhourly integrated price experienced over the corresponding two-month period in the preceding \ncalendar year, calculated separately for peak and off-peak time periods.  The two-month time \nperiods used in this calculation shall be January and February, March and April, May and June, \nJuly and August, September and October, and November and December.  \n \nExport Transaction: \n  \n“Export Transaction” shall be a transaction by a Market Participant that results in the transfer of \nenergy from within the PJM Control Area to outside the PJM Control Area.  Coordinated \nExternal Transactions that result in the transfer of energy from the PJM Control Area to an \nadjacent Control Area are one form of Export Transaction.   \n \nExport Transaction Price Factor: \n \n“Export Transaction Price Factor” for a prospective time interval shall be the greater of (i) PJM’s \nforecast price for the time interval, if available, or (ii) the Export Nodal Reference Price, but \nshall not exceed the Export Transaction’s dispatch ceiling price cap, if any, for that time interval.  \nThe Export Transaction Price Factor for a past time interval shall be calculated in the same \nmanner as for a prospective time interval, except that the Export Transaction Price Factor may \nuse a tentative or final settlement price, as available. If an Export Nodal Reference Price is not \navailable for a particular time interval, PJM may use an Export Transaction Price Factor for that \ntime interval based on an appropriate alternate reference price. \n \nExport Transaction Screening: \n \n“Export Transaction Screening” shall be the process PJM uses to review the Export Credit \nExposure of Export Transactions against the Credit Available for Export Transactions, and deny \nor curtail all or a portion of an Export Transaction, if the credit required for such transactions is \ngreater than the credit available for the transactions.   \n \nExport Transactions Net Activity: \n \n“Export Transactions Net Activity” shall mean the aggregate net total, resulting from Export \nTransactions, of (i) Spot Market Energy charges, (ii) Transmission Congestion Charges, and (iii) \nTransmission Loss Charges, calculated as set forth in Operating Agreement, Schedule 1 and the \nparallel provisions of Tariff, Attachment K-Appendix.  Export Transactions Net Activity may be \npositive or negative."},{"page":27,"startToken":8462,"endToken":8818,"text":"Extended Primary Reserve Requirement: \n \n“Extended Primary Reserve Requirement” shall equal the Primary Reserve Requirement in a \nReserve Zone or Reserve Sub-zone, plus 190 MW, plus any additional reserves scheduled under \nemergency conditions necessary to address operational uncertainty.  The Extended Primary \nReserve Requirement is calculated in accordance with the PJM Manuals.  \n \nExtended Synchronized Reserve Requirement: \n \n“Extended Synchronized Reserve Requirement” shall equal the Synchronized Reserve \nRequirement in a Reserve Zone or Reserve Sub-zone, plus 190 MW, plus any additional reserves \nscheduled under emergency conditions necessary to address operational uncertainty. The \nExtended Synchronized Reserve Requirement is calculated in accordance with the PJM Manuals. \n \nExtended 30-minute Reserve Requirement: \n \n“Extended 30-minute Reserve Requirement” shall equal the 30-minute Reserve Requirement in a \nReserve Zone or Reserve Sub-zone, plus 190 MW, plus any additional reserves scheduled under \nemergency conditions necessary to address operational uncertainty.  The Extended 30-minute \nReserve Requirement is calculated in accordance with the PJM Manuals. \n \nExternal Market Buyer: \n \n“External Market Buyer” shall mean a Market Buyer making purchases of energy from the PJM \nInterchange Energy Market for consumption by end-users outside the PJM Region, or for load in \nthe PJM Region that is not served by Network Transmission Service. \n \nExternal Resource: \n \n“External Resource” shall mean a generation resource located outside the metered boundaries of \nthe PJM Region. \n \nFacilities Study: \n \n“Facilities Study” shall be an engineering study conducted by the Transmission Provider (in \ncoordination with the affected Transmission Owner(s)) to: (1) determine the required \nmodifications to the Transmission Provider’s Transmission System necessary to implement the \nconclusions of the System Impact Study; and (2) complete any additional studies or analyses \ndocumented in the System Impact Study or required by PJM Manuals, and determine the \nrequired modifications to the Transmission Provider’s Transmission System based on the \nconclusions of such additional studies.  The Facilities Study shall include the cost and scheduled \ncompletion date for such modifications, that will be required to provide the requested \ntransmission service or to accommodate a New Service Request.  As used in the Interconnection \nService Agreement or Construction Service Agreement, Facilities Study shall mean that certain \nFacilities Study conducted by Transmission Provider (or at its direction) to determine the design"},{"page":28,"startToken":8818,"endToken":9151,"text":"and specification of the Customer Funded Upgrades necessary to accommodate the New Service \nCustomer’s New Service Request in accordance with Tariff, Part VI, section 207.  \n \nFast-Start Resource:  \n \n“Fast-Start Resource” shall have the meaning set forth in Tariff, Attachment K-Appendix, \nsection 2.2A \n \nFederal Power Act: \n \n“Federal Power Act” shall mean the Federal Power Act, as amended, 16 U.S.C. §§ 791a, et seq. \n \nFERC or Commission: \n \n“FERC” or “Commission” shall mean the Federal Energy Regulatory Commission or any \nsuccessor federal agency, commission or department exercising jurisdiction over the Tariff, \nOperating Agreement and Reliability Assurance Agreement. \n \nFERC Market Rules: \n \n “FERC Market Rules” mean the market behavior rules and the prohibition against electric \nenergy market manipulation codified by the Commission in its Rules and Regulations at 18 CFR \n§§ 1c.2 and 35.37, respectively; the Commission-approved PJM Market Rules and any related \nproscriptions or any successor rules that the Commission from time to time may issue, approve \nor otherwise establish.  \n \nFinal Offer: \n \n“Final Offer” shall mean the offer on which a resource was dispatched by the Office of the \nInterconnection for a particular clock hour for the Operating Day. \n \nFinal RTO Unforced Capacity Obligation: \n \n“Final RTO Unforced Capacity Obligation” shall mean the capacity obligation for the PJM \nRegion, determined in accordance with RAA, Schedule 8. \n \nFinancial Close: \n \n“Financial Close” shall mean the Capacity Market Seller has demonstrated that the Capacity \nMarket Seller or its agent has completed the act of executing the material contracts and/or other \ndocuments necessary to (1) authorize construction of the project and (2) establish the necessary \nfunding for the project under the control of an independent third-party entity.  A sworn, notarized \ncertification of an independent engineer certifying to such facts, and that the engineer has \npersonal knowledge of, or has engaged in a diligent inquiry to determine, such facts, shall be \nsufficient to make such demonstration.  For resources that do not have external financing, \nFinancial Close shall mean the project has full funding available, and that the project has been"},{"page":29,"startToken":9151,"endToken":9520,"text":"duly authorized to proceed with full construction of the material portions of the project by the \nappropriate governing body of the company funding such project.  A sworn, notarized \ncertification by an officer of such company certifying to such facts, and that the officer has \npersonal knowledge of, or has engaged in a diligent inquiry to determine, such facts, shall be \nsufficient to make such demonstration. \n \nFinancial Default: \n \n“Financial Default” shall mean (a) the failure of a Member or Transmission Customer to make \nany payment for obligations under the Agreements when due, including but not limited to an \ninvoice payment that has not been cured or remedied after notice has been given and any cure \nperiod has elapsed, (b) a bankruptcy proceeding filed by a Member, Transmission Customer or \nits Guarantor, or filed against a Member, Transmission Customer or its Guarantor and to which \nthe Member, Transmission Customer or Guarantor, as applicable, acquiesces or that is not \ndismissed within 60 days, (c) a Member, Transmission Customer or its Guarantor, if any, is \nunable to meet its financial obligations as they become due, or (d) a Merger Without Assumption \noccurs in respect of the Member, Transmission Customer or any Guarantor of such Member or \nTransmission Customer. \n \nFinancial Transmission Right: \n \n“Financial Transmission Right” or “FTR” shall mean a right to receive Transmission Congestion \nCredits as specified in Operating Agreement, Schedule 1, section 5.2.2 and the parallel \nprovisions of Tariff, Attachment K-Appendix, section 5.2.2. \n \nFinancial Transmission Right Obligation: \n \n“Financial Transmission Right Obligation” shall mean a right to receive Transmission \nCongestion Credits as specified in Operating Agreement, Schedule 1, section 5.2.2(b), and the \nparallel provisions of Tariff, Attachment K-Appendix, section 5.2.2(b). \n \nFinancial Transmission Right Option: \n \n“Financial Transmission Right Option” shall mean a right to receive Transmission Congestion \nCredits as specified in Operating Agreement, Schedule 1, section 5.2.2(c), and the parallel \nprovisions of Tariff, Attachment K-Appendix, section 5.2.2(c). \n \nFirm Point-To-Point Transmission Service: \n \n“Firm Point-To-Point Transmission Service” shall mean Transmission Service under the Tariff, \nPart II, section 13 that is reserved and/or scheduled between specified Points of Receipt and \nDelivery pursuant to Tariff, Part II. \n \nFirm Transmission Feasibility Study:"},{"page":30,"startToken":9520,"endToken":9805,"text":"“Firm Transmission Feasibility Study” shall mean a study conducted by the Transmission \nProvider in accordance with Tariff, Part II, section 19.3 and Tariff, Part III, section 32.3. \n \nFirm Transmission Withdrawal Rights: \n \n“Firm Transmission Withdrawal Rights” shall mean the rights to schedule energy and capacity \nwithdrawals from a Point of Interconnection of a Merchant Transmission Facility with the \nTransmission System. Firm Transmission Withdrawal Rights may be awarded only to a \nMerchant D.C. Transmission Facility that connects the Transmission System with another \ncontrol area. Withdrawals scheduled using Firm Transmission Withdrawal Rights have rights \nsimilar to those under Firm Point-to-Point Transmission Service. \n \nFirst Incremental Auction: \n \n“First Incremental Auction” shall mean an Incremental Auction conducted 20 months prior to the \nstart of the Delivery Year to which it relates. \n \nFlexible Resource:   \n“Flexible Resource” shall mean a generating resource that must have a combined Start-up Time \nand Notification Time of less than or equal to two hours; and a Minimum Run Time of less than \nor equal to two hours.   \nForecast Pool Requirement: \n \n“Forecast Pool Requirement” shall have the meaning specified in the Reliability Assurance \nAgreement.  \n \nForeign Guaranty: \n \n“Foreign Guaranty” shall mean a Corporate Guaranty provided by an Affiliate of a Participant \nthat is domiciled in a foreign country, and meets all of the provisions of Tariff, Attachment Q. \n \nForm 715 Planning Criteria: \n \n“Form 715 Planning Criteria” shall have the same meaning provided in the Operating \nAgreement. \n \nForward Daily Natural Gas Prices: \n \n“Forward Daily Natural Gas Prices” shall have the meaning provided in Tariff, Attachment DD, \nsection 5.10(a)(v-1)(E).  \n \nForward Hourly Ancillary Services Prices: \n \n“Forward Hourly Ancillary Services Prices” shall have the meaning provided in Tariff, \nAttachment DD, section 5.10(a)(v-1)(D)."},{"page":31,"startToken":9805,"endToken":10110,"text":"Forward Hourly LMPs:  \n \n“Forward Hourly LMPs” shall have the meaning provided in Tariff, Attachment DD, section \n5.10(a)(v-1)(C). \n \nFTR Credit Limit:  \n \n“FTR Credit Limit” shall mean the amount of credit established with PJMSettlement that an FTR \nParticipant has specifically designated to be used for FTR activity in a specific customer account.  \nAny such credit so set aside shall not be considered available to satisfy any other credit \nrequirement the FTR Participant may have with PJMSettlement. \n \nFTR Credit Requirement: \n \n“FTR Credit Requirement” shall mean the amount of credit that a Participant must provide in \norder to support the FTR positions that it holds and/or for which it is bidding.  The FTR Credit \nRequirement shall not include months for which the invoicing has already been completed, \nprovided that PJMSettlement shall have up to two Business Days following the date of the \ninvoice completion to make such adjustments in its credit systems.  FTR Credit Requirements \nare calculated and applied separately for each separate customer account. \n \nFTR Flow Undiversified: \n \n“FTR Flow Undiversified” shall have the meaning established in Tariff, Attachment Q, section \nVI.C.6. \n \nFTR Historical Value: \n  \nFor each FTR for each month, “FTR Historical Value” shall mean the weighted average of  \nhistorical values over three years for the FTR path using the following weightings:  50% - most \nrecent year; 30% - second year; 20% - third year.   \n \nFTR Holder: \n \n“FTR Holder” shall mean the PJM Member that has acquired and possesses an FTR. \n \nFTR Monthly Credit Requirement Contribution: \n \nFor each FTR, for each month, ”FTR Monthly Credit Requirement Contribution” shall mean the \ntotal FTR cost for the month, prorated on a daily basis, less the FTR Historical Value for the \nmonth.  For cleared FTRs, this contribution may be negative; prior to clearing, FTRs with \nnegative contribution shall be deemed to have zero contribution. \n \nFTR Net Activity:"},{"page":32,"startToken":10110,"endToken":10335,"text":"“FTR Net Activity” shall mean the aggregate net value of the billing line items for auction \nrevenue rights credits, FTR auction charges, FTR auction credits, and FTR congestion credits, \nand shall also include day-ahead and balancing/real-time congestion charges up to a maximum \nnet value of the sum of the foregoing auction revenue rights credits, FTR auction charges, FTR \nauction credits and FTR congestion credits. \n \nFTR Participant: \n \n“FTR Participant” shall mean any Market Participant that provides or is required to provide \nCollateral in order to participate in PJM’s FTR market. \n \nFTR Portfolio Auction Value: \n \n“FTR Portfolio Auction Value” shall mean for each customer account of a Market Participant, \nthe sum, calculated on a monthly basis, across all FTRs, of the FTR price times the FTR volume \nin MW.  \n \nFuel Cost Policy: \n \n“Fuel Cost Policy” shall mean the document provided by a Market Seller to PJM and the Market \nMonitoring Unit in accordance with PJM Manual 15 and Operating Agreement, Schedule 2, \nwhich documents the Market Seller’s method used to price fuel for calculation of the Market \nSeller’s cost-based offers for a generation resource.  \n \nFull Notice to Proceed: \n \n“Full Notice to Proceed” shall mean that all material third party contractors have been given the \nnotice to proceed with construction by the Capacity Market Seller or its agent, with a guaranteed \ncompletion date backed by liquidated damages."},{"page":33,"startToken":10335,"endToken":10718,"text":"Definitions – O – P - Q \n \nObligation: \n  \n“Obligation” shall mean all amounts owed to PJMSettlement for purchases from the PJM \nMarkets, Transmission Service, (under both Tariff, Part II and Tariff, Part III), and other services \nor obligations pursuant to the Agreements.  In addition, aggregate amounts that will be owed to \nPJMSettlement in the future for capacity purchases within the PJM capacity markets will be \nadded to this figure.  Should other markets be formed such that Participants may incur future \nObligations in those markets, then the aggregate amount of those Obligations will also be added \nto the Net Obligation. \n \nOffer Data: \n \n“Offer Data” shall mean the scheduling, operations planning, dispatch, new resource, and other \ndata and information necessary to schedule and dispatch generation resources and Demand \nResource(s) for the provision of energy and other services and the maintenance of the reliability \nand security of the Transmission System in the PJM Region, and specified for submission to the \nPJM Interchange Energy Market for such purposes by the Office of the Interconnection. \n \nOffice of the Interconnection: \n \n“Office of the Interconnection” shall mean the employees and agents of PJM Interconnection, \nL.L.C. subject to the supervision and oversight of the PJM Board, acting pursuant to the \nOperating Agreement. \n \nOffice of the Interconnection Control Center: \n \n“Office of the Interconnection Control Center” shall mean the equipment, facilities and \npersonnel used by the Office of the Interconnection to coordinate and direct the operation of the \nPJM Region and to administer the PJM Interchange Energy Market, including facilities and \nequipment used to communicate and coordinate with the Market Participants in connection with \ntransactions in the PJM Interchange Energy Market or the operation of the PJM Region. \n \nOn-Site Generators: \n \n“On-Site Generators” shall mean generation facilities or portions of a generation facility \n(including Behind The Meter Generation) that (i) are not Generation Capacity Resources, (ii) are \nnot injecting into the grid for the portion of a generation facility that participates as a Demand \nResource or as an Economic Load Response Participant unless permitted as an Economic Load \nResponse Regulation Only Participant, (iii) are either synchronized or non-synchronized to the \nTransmission System, and (iv) can be used to reduce demand for the purpose of participating in \nthe PJM Interchange Energy Market. \n \nOpen Access Same-Time Information System (OASIS) or PJM Open Access Same-Time \nInformation System:"},{"page":34,"startToken":10718,"endToken":11059,"text":"“Open Access Same-Time Information System,” “PJM Open Access Same-Time Information \nSystem” or “OASIS” shall mean the electronic communication and information system and \nstandards of conduct contained in Part 37 and Part 38 of the Commission’s regulations and all \nadditional requirements implemented by subsequent Commission orders dealing with OASIS for \nthe collection and dissemination of information about transmission services in the PJM Region, \nestablished and operated by the Office of the Interconnection in accordance with FERC \nstandards and requirements. \n \nOpen-Loop Hybrid Resource: \n \n“Open-Loop Hybrid Resource” shall mean a Hybrid Resource with a storage component that \noperates by charging its storage component from the grid. \n \nOperating Agreement of the PJM Interconnection, L.L.C., Operating Agreement or PJM \nOperating Agreement: \n \n“Operating Agreement of the PJM Interconnection, L.L.C.,”  “Operating Agreement” or “PJM \nOperating Agreement” shall mean the Amended and Restated Operating Agreement of PJM \nInterconnection, L.L.C. dated as of April 1, 1997 and as amended and restated as of June 2, \n1997, including all Schedules, Exhibits, Appendices, addenda or supplements hereto, as amended \nfrom time to time thereafter, among the Members of the PJM Interconnection, L.L.C., on file \nwith the Commission. \n \nOperating Day: \n \n“Operating Day” shall mean the daily 24 hour period beginning at midnight for which \ntransactions on the PJM Interchange Energy Market are scheduled. \n \nOperating Margin: \n \n“Operating Margin” shall mean the incremental adjustments, measured in megawatts, required in \nPJM Region operations in order to accommodate, on a first contingency basis, an operating \ncontingency in the PJM Region resulting from operations in an interconnected Control Area.  \nSuch adjustments may result in constraints causing Transmission Congestion Charges, or may \nresult in Ancillary Services charges pursuant to the PJM Tariff. \n \nOperating Margin Customer: \n \n“Operating Margin Customer” shall mean a Control Area purchasing Operating Margin pursuant \nto an agreement between such other Control Area and the LLC. \n \nOperating Reserve Demand Curve: \n \n“Operating Reserve Demand Curve” shall mean a curve with prices on the y-axis and megawatts \non the x-axis, which defines the relationship between each incremental megawatt of reserves that"},{"page":35,"startToken":11059,"endToken":11341,"text":"can be used to meet a given reserve requirement. \n \nOperationally Deliverable: \n \n“Operationally Deliverable” shall mean, as determined by the Office of the Interconnection, that \nthere are no operational conditions, arrangements or limitations experienced or required that \nthreaten, impair or degrade effectuation or maintenance of deliverability of capacity or energy \nfrom the external Generation Capacity Resource to loads in the PJM Region in a manner \ncomparable to the deliverability of capacity or energy to such loads from Generation Capacity \nResources located inside the metered boundaries of the PJM Region, including, without \nlimitation, an identified need by an external Balancing Authority Area for a remedial action \nscheme or manual generation trip protocol, transmission facility switching arrangements  that \nwould have the effect of radializing load, or excessive or unacceptable frequency of regional \nreliability limit violations or (outside an interregional agreed congestion management process) of \nlocal reliability dispatch instructions and commitments. \n \nOpportunity Cost: \n \n“Opportunity Cost” shall mean a component of the Market Seller Offer Cap calculated in \naccordance with Tariff, Attachment DD, section 6. \n \nOPSI Advisory Committee: \n \n“OPSI Advisory Committee” shall mean the committee established under Tariff, Attachment M, \nsection III.G. \n \nOption to Build: \n \n“Option to Build” shall mean the option of the New Service Customer to build certain Customer-\nFunded Upgrades, as set forth in, and subject to the terms of, the Construction Service \nAgreement. \n \nOptional Interconnection Study: \n \n“Optional Interconnection Study” shall mean a sensitivity analysis of an Interconnection Request \nbased on assumptions specified by the Interconnection Customer in the Optional Interconnection \nStudy Agreement. \n \nOptional Interconnection Study Agreement: \n \n“Optional Interconnection Study Agreement” shall mean the form of agreement for preparation \nof an Optional Interconnection Study, as set forth in Tariff, Attachment N-3. \n \nPart I:"},{"page":36,"startToken":11341,"endToken":11614,"text":"“Part I” shall mean the Tariff Definitions and Common Service Provisions contained in Tariff, \nPart I, sections 1 through 12A. \n \nPart II: \n \n“Part II” shall mean Tariff, Part II, sections 13 through 27A pertaining to Point-To-Point \nTransmission Service in conjunction with the applicable Common Service Provisions of Tariff, \nPart I and appropriate Schedules and Attachments. \n \nPart III: \n \n“Part III” shall mean Tariff, Part III, sections 28 through 35 pertaining to Network Integration \nTransmission Service in conjunction with the applicable Common Service Provisions of Tariff, \nPart I and appropriate Schedules and Attachments. \n \nPart IV: \n \n“Part IV” shall mean Tariff, Part IV, sections 36 through 112C pertaining to generation or \nmerchant transmission interconnection to the Transmission System in conjunction with the \napplicable Common Service Provisions of Tariff, Part I and appropriate Schedules and \nAttachments. \n \nPart V: \n \n“Part V” shall mean Tariff, Part V, sections 113 through 122 pertaining to the deactivation of \ngenerating units in conjunction with the applicable Common Service Provisions of Tariff, Part I \nand appropriate Schedules and Attachments. \n \nPart VI: \n \n“Part VI” shall mean Tariff, Part VI, sections 200 through 237 pertaining to the queuing, study, \nand agreements relating to New Service Requests, and the rights associated with Customer-\nFunded Upgrades in conjunction with the applicable Common Service Provisions of Tariff, Part I \nand appropriate Schedules and Attachments. \n \nParticipant: \n  \n“Participant” shall mean a Market Participant and/or Transmission Customer and/or Applicant \nrequesting to be an active Market Participant and/or Transmission Customer. \n \nParties: \n \n“Parties” shall mean the Transmission Provider, as administrator of the Tariff, and the \nTransmission Customer receiving service under the Tariff.  PJMSettlement shall be the \nCounterparty to Transmission Customers."},{"page":37,"startToken":11614,"endToken":12028,"text":"Peak-Hour Dispatch: \n \n“Peak-Hour Dispatch” shall mean, for purposes of calculating the Energy and Ancillary Services \nRevenue Offset under Tariff, Attachment DD, section 5, an assumption, as more fully set forth in \nthe PJM Manuals, that the Reference Resource is committed in the Day-ahead Energy Market in \nfour distinct blocks of four hours of continuous output for each block from the peak-hour period \nbeginning with the hour ending 0800 EPT through to the hour ending 2300 EPT for any day \nwhen the average day-ahead LMP for the area for which the Net Cost of New Entry is being \ndetermined is greater than, or equal to, the cost to generate (including the cost for a complete \nstart and shutdown cycle), plus 10% of such costs only for the 2022/2023 Delivery Year, for at \nleast two hours during each four-hour block, where such blocks shall be assumed to be  \ncommitted independently; provided that, if there are not at least two economic hours in any given \nfour-hour block, then the Reference Resource shall be assumed not to be committed for such \nblock; and to the extent not committed in any such block in the Day-ahead Energy Market under \nthe above conditions based on Day-Ahead LMPs, is dispatched in the Real-time Energy Market \nfor such block if the Real-Time LMP is greater than or equal to the cost to generate, plus 10% of \nsuch costs only for the 2022/2023 Delivery Year, under the same conditions as described above \nfor the Day-ahead Energy Market. \n \nPeak Market Activity:   \n \n“Peak Market Activity” shall mean a measure of exposure for which credit is required, calculated \nin accordance with Tariff, Attachment Q, section VII.A.  \n \nPeak Market Activity Shortfall: \n \n“Peak Market Activity Shortfall” shall mean, for any given week, the amount by which a \nParticipant’s current Peak Market Activity exceeds such Participant’s Peak Market Activity \ncredit requirement from the prior week. \n \nPeak Market Activity Surplus: \n \n“Peak Market Activity Surplus” shall mean, for any given week, the amount by which a \nParticipant’s Peak Market Activity credit requirement from the prior week exceeds such \nParticipant’s current Peak Market Activity. \n \nPeak Season: \n \n“Peak Season” shall mean the weeks containing the 24th through 36th Wednesdays of the \ncalendar year.  Each such week shall begin on a Monday and end on the following Sunday, \nexcept for the week containing the 36th Wednesday, which shall end on the following Friday. \n \nPercentage Internal Resources Required: \n \n“Percentage Internal Resources Required” shall have the meaning specified in the Reliability \nAssurance Agreement."},{"page":38,"startToken":12028,"endToken":12368,"text":"Performance Assessment Interval: \n \n“Performance Assessment Interval” shall mean each Real-time Settlement Interval for which an \nEmergency Action has been declared by the Office of the Interconnection, provided, however, \nthat Performance Assessment Intervals for a Base Capacity Resource shall not include any \nintervals outside the calendar months of June through September. \n \nPermissible Technological Advancement: \n \n“Permissible Technological Advancement” shall mean a proposed technological change such as \nan advancement to turbines, inverters, plant supervisory controls or other similar advancements \nto the technology proposed in the Interconnection Request that is submitted to the Transmission \nProvider no later than the return of an executed Facilities Study Agreement (or, if a Facilities \nStudy is not required, prior to the return of an executed Interconnection Service Agreement).  \nProvided such change may not:  (i) increase the capability of the Generating Facility as specified \nin the original Interconnection Request; (ii) represent a different fuel type from the original \nInterconnection Request; or (iii) cause any material adverse impact(s) on the Transmission \nSystem with regard to short circuit capability limits, steady-state thermal and voltage limits, or \ndynamic system stability and response.  If the proposed technological advancement is a \nPermissible Technological Advancement, no additional study will be necessary and the proposed \ntechnological advancement will not be considered a Material Modification. \n \nPJM:   \n \n“PJM” shall mean PJM Interconnection, L.L.C., including the Office of the Interconnection as \nreferenced in the PJM Operating Agreement.  When such term is being used in the RAA it shall \nalso include the PJM Board. \n \nPJM Administrative Service: \n \n“PJM Administrative Service” shall mean the services provided by PJM pursuant to Tariff, \nSchedule 9. \n \nPJM Board: \n \n“PJM Board” shall mean the Board of Managers of the LLC, acting pursuant to the Operating \nAgreement except when such term is being used in Tariff, Attachment M, in which case PJM \nBoard shall mean the Board of Managers of PJM or its designated representative, exclusive of \nany members of PJM Management. \n \nPJM Control Area: \n \n“PJM Control Area” shall mean the Control Area recognized by NERC as the PJM Control Area. \n \nPJM Entities:"},{"page":39,"startToken":12368,"endToken":12805,"text":"“PJM Entities” shall mean PJM, including the Market Monitoring Unit, the PJM Board, and PJM’s \nofficers, employees, representatives, advisors, contractors, and consultants. \n \nPJM Interchange: \n \n“PJM Interchange” shall mean the following, as determined in accordance with the Operating \nAgreement and Tariff: (a) for a Market Participant that is a Network Service User, the amount by \nwhich its interval Equivalent Load exceeds, or is exceeded by, the sum of the interval outputs of \nits operating generating resources; or (b) for a Market Participant that is not a Network Service \nUser, the amount of its Spot Market Backup; or (c) the interval scheduled deliveries of Spot \nMarket Energy by a Market Seller from an External Resource; or (d) the interval net metered \noutput of any other Market Seller; or (e) the interval scheduled deliveries of Spot Market Energy \nto an External Market Buyer; or (f) the inteval scheduled deliveries to an Internal Market Buyer \nthat is not a Network Service User. \n \nPJM Interchange Energy Market: \n \n“PJM Interchange Energy Market” shall mean the regional competitive market administered by \nthe Office of the Interconnection for the purchase and sale of spot electric energy at wholesale in \ninterstate commerce and related services established pursuant to Operating Agreement, Schedule \n1, and the parallel provisions of Tariff, Attachment K – Appendix. \n \nPJM Interchange Export: \n \n“PJM Interchange Export” shall mean the following, as determined in accordance with the \nOperating Agreement and Tariff:  (a) for a Market Participant that is a Network Service User, the \namount by which its interval Equivalent Load is exceeded by the sum of the inteval outputs of its \noperating generating resources; or (b) for a Market Participant that is not a Network Service \nUser, the amount of its Spot Market Backup sales; or (c) the interval scheduled deliveries of Spot \nMarket Energy by a Market Seller from an External Resource; or (d) the interval net metered \noutput of any other Market Seller. \n \nPJM Interchange Import: \n \n“PJM Interchange Import” shall mean the following, as determined in accordance with the \nOperating Agreement and Tariff:  (a) for a Market Participant that is a Network Service User, the \namount by which its interval Equivalent Load exceeds the sum of the interval outputs of its \noperating generating resources; or (b) for a Market Participant that is not a Network Service \nUser, the amount of its Spot Market Backup purchases; or (c) the interval scheduled deliveries of \nSpot Market Energy to an External Market Buyer; or (d) the interval scheduled deliveries to an \nInternal Market Buyer that is not a Network Service User. \n \nPJM Liaison: \n \n“PJM Liaison” shall mean the liaison established under Tariff, Attachment M, section III.I."},{"page":40,"startToken":12805,"endToken":13131,"text":"PJM Management: \n \n“PJM Management” shall mean the officers, executives, supervisors and employee managers of \nPJM. \n \nPJM Manuals: \n \n“PJM Manuals” shall mean the instructions, rules, procedures and guidelines established by the \nOffice of the Interconnection for the operation, planning, and accounting requirements of the \nPJM Region and the PJM Interchange Energy Market. \n \nPJM Markets: \n \n“PJM Markets” shall mean the PJM Interchange Energy Market, capacity markets, including the \nRPM auctions, and any other market operated by PJM, together with all bilateral or other wholesale \nelectric power and energy transactions, capacity transactions, ancillary services transactions \n(including black start service), transmission transactions, Financial Transmission Rights \ntransactions, or transactions in any other market operated under the Agreements within the PJM \nRegion, wherein Market Participants may incur Obligations to PJM and/or PJMSettlement. \n \nPJM Market Rules: \n \n“PJM Market Rules” shall mean the rules, standards, procedures, and practices of the PJM \nMarkets set forth in the PJM Tariff, the PJM Operating Agreement, the PJM Reliability \nAssurance Agreement, the PJM Consolidated Transmission Owners Agreement, the PJM \nManuals, the PJM Regional Practices Document, the PJM-Midwest Independent Transmission \nSystem Operator Joint Operating Agreement or any other document setting forth market rules. \n \nPJM Net Assets: \n \n“PJM Net Assets” shall mean the total assets per PJM’s consolidated quarterly or year-end \nfinancial statements most recently issued as of the date of the receipt of written notice of a claim \nless amounts for which PJM is acting as a temporary custodian on behalf of its Members, \ntransmission developers/Designated Entities, and generation developers, including, but not \nlimited to, cash deposits related to credit requirement compliance, study and/or interconnection \nreceivables, member prepayments, invoiced amounts collected from Net Buyers but have not yet \nbeen paid to Net Sellers, and excess congestion (as described in Operating Agreement, Schedule \n1, section 5.2.6, and the parallel provisions of Tariff, Attachment K-Appendix, section 5.2.6). \n \nPJM Region: \n \n“PJM Region” shall have the meaning specified in the Operating Agreement.  \n \nPJM Regional Practices Document:"},{"page":41,"startToken":13131,"endToken":13450,"text":"“PJM Regional Practices Document” shall mean the document of that title that compiles and \ndescribes the practices in the PJM Markets and that is made available in hard copy and on the \nInternet. \n \nPJM Region Installed Reserve Margin: \n \n“PJM Region Installed Reserve Margin” shall mean the percent installed reserve margin for the \nPJM Region required pursuant to RAA, Schedule 4.1, as approved by the PJM Board. \n \nPJM Region Peak Load Forecast: \n \n“PJM Region Peak Load Forecast” shall mean the peak load forecast used by the Office of the \nInterconnection in determining the PJM Region Reliability Requirement, and shall be determined \non both a preliminary and final basis as set forth in Tariff, Attachment DD, section 5.   \n \nPJM Region Reliability Requirement:  \n \n“PJM Region Reliability Requirement” shall mean, for purposes of the Base Residual Auction, \nthe Forecast Pool Requirement multiplied by the Preliminary PJM Region Peak Load Forecast, \nless the sum of all Preliminary Unforced Capacity Obligations of FRR Entities in the PJM \nRegion; and, for purposes of the  Incremental Auctions, the Forecast Pool Requirement \nmultiplied by the updated PJM Region Peak Load Forecast, less the sum of all updated Unforced \nCapacity Obligations of FRR Entities in the PJM Region. \n \nPJMSettlement:   \n \n“PJM Settlement” or “PJM Settlement, Inc.” shall mean PJM Settlement, Inc. (or its successor), \nestablished by PJM as set forth in Operaitng Agreement, section 3.3. \n \nPJM Tariff, Tariff, O.A.T.T., OATT or PJM Open Access Transmission Tariff: \n \n“PJM Tariff,” “Tariff,” “O.A.T.T.,” “OATT,” or “PJM Open Access Transmission Tariff” shall \nmean that certain PJM Open Access Transmission Tariff, including any schedules, appendices or \nexhibits attached thereto, on file with FERC and as amended from time to time thereafter. \n \nPlan: \n \n“Plan” shall mean the PJM market monitoring plan set forth in Tariff, Attachment M. \n \nPlanned Demand Resource: \n \n“Planned Demand Resource” shall have the meaning specified in the Reliability Assurance \nAgreement. \n \nPlanned External Generation Capacity Resource:"},{"page":42,"startToken":13450,"endToken":13723,"text":"“Planned External Generation Capacity Resource” shall have the meaning specified in the \nReliability Assurance Agreement. \n \nPlanned Generation Capacity Resource: \n \n“Planned Generation Capacity Resource” shall have the meaning specified in the Reliability \nAssurance Agreement. \n \nPlanning Period: \n \n“Planning Period” shall mean the 12 moths beginning June 1 and extending through May 31 of \nthe following year, or such other period approved by the Members Committee. \n \nPlanning Period Balance: \n \n“Planning Period Balance” shall mean the entire period of time remaining in the Planning Period \nfollowing the month that a monthly auction is conducted.  \n \nPlanning Period Quarter: \n \n“Planning Period Quarter” shall mean any of the following three month periods in the Planning \nPeriod: June, July and August; September, October and November; December, January and \nFebruary; or March, April and May. \n \nPoint(s) of Delivery: \n \n“Point(s) of Delivery” shall mean the point(s) on the Transmission Provider’s Transmission \nSystem where capacity and energy transmitted by the Transmission Provider will be made \navailable to the Receiving Party under Tariff, Part II.  The Point(s) of Delivery shall be specified \nin the Service Agreement for Long-Term Firm Point-To-Point Transmission Service. \n \nPoint of Interconnection: \n \n“Point of Interconnection” shall mean the point or points where the Customer Interconnection \nFacilities interconnect with the Transmission Owner Interconnection Facilities or the \nTransmission System. \n \nPoint(s) of Receipt: \n \n“Point(s) of Receipt” shall mean point(s) of interconnection on the Transmission Provider’s \nTransmission System where capacity and energy will be made available to the Transmission \nProvider by the Delivering Party under Tariff, Part II.  The Point(s) of Receipt shall be specified \nin the Service Agreement for Long-Term Firm Point-To-Point Transmission Service. \n \nPoint-To-Point Transmission Service:"},{"page":43,"startToken":13723,"endToken":13989,"text":"“Point-To-Point Transmission Service shall mean the reservation and transmission of capacity \nand energy on either a firm or non-firm basis from the Point(s) of Receipt to the Point(s) of \nDelivery under Tariff, Part II. \n \nPower Purchaser: \n \n“Power Purchaser” shall mean the entity that is purchasing the capacity and energy to be \ntransmitted under the Tariff. \n \nPRD Curve: \n \n“PRD Curve” shall have the meaning provided in the Reliability Assurance Agreement. \n \nPRD Provider: \n \n“PRD Provider” shall have the meaning provided in the Reliability Assurance Agreement. \n \nPRD Reservation Price: \n \n“PRD Reservation” Price shall have the meaning provided in the Reliability Assurance \nAgreement. \n \nPRD Substation:   \n \n“PRD Substation” shall have the meaning provided in the Reliability Assurance Agreement. \n \nPre-Confirmed Application: \n \n“Pre-Confirmed Application” shall be an Application that commits the Eligible Customer to \nexecute a Service Agreement upon receipt of notification that the Transmission Provider can \nprovide the requested Transmission Service. \n \nPre-Emergency Load Response Program: \n \n“Pre-Emergency Load Response Program” shall be the program by which Curtailment Service \nProviders may be compensated by PJM for Demand Resources that will reduce load when \ndispatched by PJM during pre-emergency conditions, and is described in Operating Agreement, \nSchedule 1, section 8 and the parallel provisions of Tariff, Attachment K-Appendix, section 8.  \n \nPre-Expansion PJM Zones: \n \n“Pre-Expansion PJM Zones” shall be zones included in the Tariff, along with applicable \nSchedules and Attachments, for certain Transmission Owners – Atlantic City Electric Company, \nBaltimore Gas and Electric Company, Delmarva Power and Light Company, Jersey Central \nPower and Light Company, Mid-Atlantic Interstate Transmission, LLC (“MAIT”) (MAIT owns \nand operates the transmission facilities in the Metropolitan Edison Company Zone and the"},{"page":44,"startToken":13989,"endToken":14335,"text":"Pennsylvania Electric Company Zone), PECO Energy Company, Pennsylvania Power & Light \nGroup, Potomac Electric Power Company, Public Service Electric and Gas Company, Allegheny \nPower, and Rockland Electric Company. \n \nPrice Responsive Demand: \n \n“Price Responsive Demand” shall have the meaning provided in the Reliability Assurance \nAgreement. \n \nPrimary Reserve: \n \n“Primary Reserve” shall mean the total reserve capability of generation resources that can be \nconverted fully into energy or Economic Load Response Participant resources whose demand \ncan be reduced within ten minutes of a request from the Office of the Interconnection dispatcher, \nand is comprised of both Synchronized Reserve and Non-Synchronized Reserve. \n \nPrimary Reserve Alert \n \n“Primary Reserve Alert” shall mean a notification from PJM to alert Members of an anticipated \nshortage of Operating Reserve capacity for a future critical period. \n \nPrimary Reserve Requirement: \n \n“Primary Reserve Requirement” shall mean the megawatts required to be maintained in a \nReserve Zone or Reserve Sub-zone as Primary Reserve absent any increase to account for \nadditional reserves scheduled to address operational uncertainty.  The Primary Reserve \nRequirement is calculated in accordance with the PJM Manuals.  The requirement can be \nsatisfied by any combination of Synchronized Reserve or Non-Synchronized Reserve resources. \n \nPrincipal: \n \n“Principal” shall mean (i) all natural persons who Control Corporate Level Strategy for the \nParticipant, which shall include a chief executive officer, managing member (or equivalent \npositions regardless of title) and members of a board of directors or board of managers; (ii) the \nchief legal officer or general counsel (or equivalent position regardless of title); (iii) the natural \nperson who Controls the financial affairs and investments of the Participant, which shall include \na chief financial officer (or equivalent position regardless of title); (iv) the natural person who \nControls the Participant’s management of commodity and derivatives market risks, which shall \ninclude a chief risk officer (or equivalent position regardless of title); (v) the natural person who \nControls the Participant’s transactions in the applicable PJM Markets (regardless of title); and \n(vi) all Beneficial Owners.  \n \n“Control,” as that term is used in this definition, refers to possession of the power to direct the \nmanagement or policies of an entity."},{"page":45,"startToken":14335,"endToken":14856,"text":"“Corporate Level Strategy,” as that term is used in this definition, refers to the highest-level \nstrategy of an entity, focused on the entity’s overall direction rather than the day-to-day \noperations of the entity. \n \n“Beneficial Owner,” as that term is used in this definition, means a natural person who, directly \nor indirectly, alone or together with such person’s Family Members, owns, controls, or holds \nwith power to vote 10 percent or more of the outstanding securities of the Participant.  \n \n“Family Member,” as that term is used in this definition of “Beneficial Owner,” means a spouse, \ndomestic partner, parent, child, or sibling.  \n \nFor purposes of trusts with, directly or indirectly, 10 percent or more of the outstanding \nsecurities of the Participant as described above, the following are Beneficial Owners: (a) a \nnatural person trustee; (b) a natural person with the authority to dispose of the trust assets; (c) a \nnatural person grantor or settlor who has the right to revoke the trust or otherwise withdraw the \nassets of the trust; and (d) a natural person beneficiary who is the sole permissible recipient of \nincome and principal from the trust or has the right to demand a distribution of or withdraw \nsubstantially all of the assets from the trust. \n \nIf, due to the Participant’s business enterprise, structure or otherwise, a function described in \nclauses (i) through (v) above is performed by a natural person or entity separate from the \nParticipant (such as a risk management department in an affiliate, or a director or manager at an \nentity that controls or invests in the Participant), then for that Participant the term Principal shall \nmean that natural person, or the senior officer or manager of that entity, that performs such \nfunction. \n \nPrior CIL Exception External Resource: \n \n“Prior CIL Exception External Resource” shall mean an external Generation Capacity Resource \nfor which (1) a Capacity Market Seller had, prior to May 9, 2017, cleared a Sell Offer in an RPM \nAuction under the exception provided to the definition of Capacity Import Limit as set forth in \nRAA, Article I or (2) an FRR Entity committed, prior to May 9, 2017, in an FRR Capacity Plan \nunder the exception provided in the definition of Capacity Import Limit.  In the event only a \nportion (in MW) of an external Generation Capacity Resource has a Pseudo-Tie into the PJM \nRegion, that portion of the external Generation Capacity Resource, which can include up to the \nmaximum megawatt amount cleared in any prior RPM auction or committed in an FRR Capacity \nPlan (and no other portion thereof) is eligible for treatment as a Prior CIL Exception External \nResource if such portion satisfies the requirements of the first sentence of this definition. \n \nProject Financing: \n \n“Project Financing” shall mean:  (a) one or more loans, leases, equity and/or debt financings, \ntogether with all modifications, renewals, supplements, substitutions and replacements thereof, \nthe proceeds of which are used to finance or refinance the costs of the Customer Facility, any \nalteration, expansion or improvement to the Customer Facility, the purchase and sale of the \nCustomer Facility or the operation of the Customer Facility; (b) a power purchase agreement"},{"page":46,"startToken":14856,"endToken":15259,"text":"pursuant to which Interconnection Customer’s obligations are secured by a mortgage or other \nlien on the Customer Facility; or (c) loans and/or debt issues secured by the Customer Facility. \n \nProject Finance Entity: \n \n“Project Finance Entity” shall mean:  (a) a holder, trustee or agent for holders, of any component \nof Project Financing; or (b) any purchaser of capacity and/or energy produced by the Customer \nFacility to which Interconnection Customer has granted a mortgage or other lien as security for \nsome or all of Interconnection Customer’s obligations under the corresponding power purchase \nagreement. \n \nProjected EAS Dispatch: \n \n“Projected EAS Dispatch” shall mean, for purposes of calculating the Net Energy and Ancillary \nServices Revenue Offset, a simulated dispatch with the objective of committing and dispatching \na resource for the purpose of maximizing its net revenues. The calculation shall take inputs \nincluding Forward Hourly LMPs, Forward Hourly Ancillary Service Prices, and Forward Daily \nNatural Gas Prices or forecasted fuel prices, as applicable, in addition to the operating \nparameters and costs of the specific resource, including the cost emission allowances. Using \noperating parameters, forward or forecasted fuel prices, as applicable and other cost pricing \ninputs, a composite, cost-based energy offer is created for the resource such that its commitment \nand dispatch is co-optimized between energy and ancillary services in the Day-Ahead Energy \nMarket and then the Real-Time Energy Market considering the electricity and ancillary service \nprice inputs. In the Real-Time Energy Market co-optimization, the resource is assumed to be \noperating in the hours it was scheduled in the Day-Ahead Energy Market but is dispatched \naccording to the real-time price inputs. In the hours where the resource was not committed in the \nDay-Ahead Market, the resource may be committed and dispatched in real-time only subject to \nthe real-time electricity and ancillary service price inputs and the resource’s offer and operating \nparameters.  For combustion turbine units only, the cost-based energy offer will include a 10 \npercent adder only for the 2022/2023 Delivery Year. \n \nProjected PJM Market Revenues: \n \n“Projected PJM Market Revenues” shall mean a component of the Market Seller Offer Cap \ncalculated in accordance with Tariff, Attachment DD, section 6. \n \nProportional Multi-Driver Project: \n \n“Proportional Multi-Driver Project” shall have the same meaning provided in the Operating \nAgreement. \n \nProvisional Interconnection Service: \n \n“Provisional Interconnection Service” shall mean interconnection service provided by \nTransmission Provider associated with interconnecting the Interconnection Customer’s Generating \nFacility to Transmission Provider’s Transmission System and enabling that Transmission System"},{"page":47,"startToken":15259,"endToken":15560,"text":"to receive electric energy and capacity from the Generating Facility at the Point of Interconnection, \npursuant to the terms of the Interconnection Service Agreement and, if applicable, the Tariff. \n \nPseudo-Tie: \n \n“Pseudo-Tie” shall have the same meaning provided in the Operating Agreement. \n \nPublic Policy Objectives: \n \n“Public Policy Objectives” shall have the same meaning provided in the Operating Agreement. \n \nPublic Policy Requirements: \n \n“Public Policy Requirements” shall have the same meaning provided in the Operating \nAgreement. \n \nQualifying RBP Offset UCAP MW: \n \n“Qualifying RBP Offset UCAP MW” shall mean unforced capacity that: (i) pursuant to Tariff, \nAttachment DD, section 18.2, has not received an RPM commitment or been committed in an \nFRR Plan as of the commencement of the Reliability Backstop Procurement, (ii) is supplied by \neligible Capacity Resources in accordance with Tariff, Attachment DD, section 18.2(b), and (iii) \nis supported by evidence, in accordance with Tariff, Attachment DD, section 18.2(c). \n \nQualifying Transmission Upgrade: \n \n“Qualifying Transmission Upgrade” shall mean a proposed enhancement or addition to the \nTransmission System that: (a) will increase the Capacity Emergency Transfer Limit into an LDA \nby a megawatt quantity certified by the Office of the Interconnection; (b) the Office of the \nInterconnection has determined will be in service on or before the commencement of the first \nDelivery Year for which such upgrade is the subject of a Sell Offer in the Base Residual \nAuction; (c) is the subject of a Facilities Study Agreement executed before the conduct of the \nBase Residual Auction for such Delivery Year and (d) a New Service Customer is obligated to \nfund through a rate or charge specific to such facility or upgrade. \n \nQueue Position: \n \n“Queue Position” shall mean the priority assigned to an Interconnection Request, a Completed \nApplication, or an Upgrade Request pursuant to applicable provisions of Tariff, Part VI."},{"page":48,"startToken":15560,"endToken":15815,"text":"Definitions – R - S \n \nRamping Capability: \n \n“Ramping Capability” shall mean the sustained rate of change of generator output, in megawatts \nper minute. \n \nRating Agency: \n \n“Rating Agency” shall mean a Nationally Recognized Statistical Rating Organization that \nassesses the financial condition, strength and stability of companies and governmental entities \nand their ability to timely make principal and interest payments on their debts and the likelihood \nof default, and assigns a rating that reflects its assessment of the ability of the company or \ngovernmental entity to make the debt payments. \n \nRBP Charges: \n \n“RBP Charges” shall mean the $/day value of the total RBP Settlement Credits, positive or \nnegative, of all committed RBP Resources across the PJM Region. \n \nRBP Collateral: \n \n“RBP Collateral” shall mean: either (1) a cash deposit, including any interest thereon, or (2) a \nletter of credit issued for the benefit of PJM or PJMSettlement, in an amount and form \ndetermined by and acceptable to PJM or PJMSettlement. \n \nRBP Obligation: \n \n“RBP Obligation” or “RBO” shall mean the state and/or RERRA-determined allocation of RBP \nUCAP MW to Load Serving Entities within each Electric Distributor’s zone/area. \n \nRBP Resources: \n \n“RBP Resources” shall mean generation resources, Energy Storage Resources, Demand \nResources, or DER Aggregation Resources, as set forth in Tariff, Attachment DD, section 18.5, \noffered to provide RBP UCAP MW from the Reliability Backstop Procurement, in accordance \nwith Tariff, Attachment DD, section 18. \n \nRBP Seller: \n \n“RBP Seller” shall mean an entity that owns or controls an RBP Resource that is offered into the \nReliability Backstop Procurement. \n \n \nRBP Sell Offer:"},{"page":49,"startToken":15815,"endToken":16087,"text":"“RBP Sell Offer” shall mean an offer to sell RBP Resources in the Reliability Backstop \nProcurement. \n \nRBP Settlement Credits: \n \n“RBP Settlement Credits” shall mean, for each day in the Delivery Year in the term of the \nReliability Backstop Procurement commitment period, the $/day value that a resource committed \nin the Reliability Backstop Procurement receives as a contract for differences settlement in \naccordance with Tariff, Attachment DD, section 18.5(g). \n \nRBP UCAP MW: \n \n“RBP UCAP MW” shall mean unforced capacity that is eligible to be offered in the Reliability \nBackstop Procurement, in accordance with Tariff, Attachment DD, section 18. \n \nReal-time Congestion Price: \n \n“Real-time Congestion Price” shall mean the Congestion Price resulting from the Office of the \nInterconnection’s dispatch of the PJM Interchange Energy Market in the Operating Day. \n \nReal-time Loss Price: \n \n“Real-time Loss Price” shall mean the Loss Price resulting from the Office of the \nInterconnection’s dispatch of the PJM Interchange Energy Market in the Operating Day. \n \nReal-time Energy Market: \n \n“Real-time Energy Market” shall mean the purchase or sale of energy and payment of \nTransmission Congestion Charges for quantity deviations from the Day-ahead Energy Market in \nthe Operating Day. \n \nReal-time Offer: \n \n“Real-time Offer” shall mean a new offer or an update to a Market Seller’s existing cost-based or \nmarket-based offer for a clock hour, submitted for use after the close of the Day-ahead Energy \nMarket. \n \nReal-time Prices: \n \n“Real-time Prices” shall mean the Locational Marginal Prices resulting from the Office of the \nInterconnection’s dispatch of the PJM Interchange Energy Market in the Operating Day. \n \nReal-time Settlement Interval: \n \n“Real-time Settlement Interval” shall mean the interval used by settlements, which shall be every \nfive minutes."},{"page":50,"startToken":16087,"endToken":16439,"text":"Real-time State of Charge: \n \n“Real-time State of Charge” shall mean the current State of Charge of an Energy Storage \nResource Model Participant, measured in units of megawatt-hours. \n \nReal-time System Energy Price: \n \n“Real-time System Energy Price” shall mean the System Energy Price resulting from the Office \nof the Interconnection’s dispatch of the PJM Interchange Energy Market in the Operating Day. \n \nReasonable Efforts: \n \n“Reasonable Efforts” shall mean, with respect to any action required to be made, attempted, or \ntaken by an Interconnection Party or by a Construction Party under Tariff, Part IV or Tariff, Part \nVI, an Interconnection Service Agreement, or a Construction Service Agreement, such efforts as \nare timely and consistent with Good Utility Practice and with efforts that such party would \nundertake for the protection of its own interests. \n \nReceiving Party: \n \n“Receiving Party” shall mean the entity receiving the capacity and energy transmitted by the \nTransmission Provider to Point(s) of Delivery. \n \nReferral: \n \n“Referral” shall mean a formal report of the Market Monitoring Unit to the Commission for \ninvestigation of behavior of a Market Participant, of behavior of PJM, or of a market design \nflaw, pursuant to Tariff, Attachment M, section IV.I. \n \nReference Resource: \n \nFor Delivery Years up to and including the 2025/2026 Delivery Year, “Reference Resource” \nshall mean a combustion turbine generating station, configured with a single General Electric \nFrame 7HA turbine with evaporative cooling, Selective Catalytic Reduction technology, dual \nfuel capability, and a heat rate of 9.134 Mmbtu/ MWh.  For the 2026/2027 through and including \nthe 2027/2028 Delivery Years, “Reference Resource” shall mean, for all CONE Areas, a \ncombustion turbine generating station, configured with a single General Electric Frame 7HA \nturbine with evaporative cooling, Selective Catalytic Reduction technology, dual fuel capability, \nand a heat rate of 9.189 Mmbtu/MWh.  For the 2028/2029 Delivery Year and subsequent \nDelivery Years, “Reference Resource” shall mean a combustion turbine generation station, \nconfigured with a single 1x0 GE Frame 7HA.03 turbine with evaporative cooling, no inlet \nchillers, wet compression, Selective Catalytic Reduction technology, dual fuel capability, and a \nheat rate of 9.199 MMBtu/MWh. \n \nRegional Entity:"},{"page":51,"startToken":16439,"endToken":16738,"text":"“Regional Entity” shall have the same meaning specified in the Operating Agreement. \n \nRegional Network Integration Transmission Service:  \n \n“Regional Network Integration Transmission Service” shall mean firm transmission service \ntaken by Network Customers that involves the delivery of energy and/or capacity from Network \nResources physically interconnected to the Transmission Provider’s transmission system to \nNetwork Load physically interconnected to the Transmission Provider’s transmission system. \n \nRegional Transmission Expansion Plan: \n \n“Regional Transmission Expansion Plan” shall mean the plan prepared by the Office of the \nInterconnection pursuant to Operating Agreement, Schedule 6 for the enhancement and \nexpansion of the Transmission System in order to meet the demands for firm transmission \nservice in the PJM Region. \n \nRegional Transmission Group (RTG): \n \n“Regional Transmission Group” or “RTG” shall mean a voluntary organization of transmission \nowners, transmission users and other entities approved by the Commission to efficiently \ncoordinate transmission planning (and expansion), operation and use on a regional (and \ninterregional) basis. \n \nRegulation: \n \n“Regulation” shall mean the capability of a specific generation resource or Demand Resource \nwith appropriate telecommunications, control and response capability to separately increase and \ndecrease its output or adjust load in response to a regulating control signal, in accordance with \nthe specifications in the PJM Manuals. \n \nRegulation Requirement: \n \n“Regulation Requirement” shall mean the required megawatts of performance-adjusted \nRegulation capability to be maintained in a Regulation Zone. The Regulation Requirement is \ndefined as a set megawatt value by commitment interval and can increase to account for \nadditional operational uncertainty, in accordance with the PJM Manuals. \n \nRegulation Zone: \n \n“Regulation Zone” shall mean any of those one or more geographic areas, each consisting of a \ncombination of one or more Control Zone(s) as designated by the Office of the Interconnection \nin the PJM Manuals, relevant to provision of, and requirements for, regulation service. \n \nRelevant Electric Retail Regulatory Authority:"},{"page":52,"startToken":16738,"endToken":17129,"text":"“Relevant Electric Retail Regulatory Authority” shall mean an entity that has jurisdiction over \nand establishes prices and policies for competition for providers of retail electric service to end-\ncustomers, such as the city council for a municipal utility, the governing board of a cooperative \nutility, the state public utility commission or any other such entity. \n \nReliability Assurance Agreement or PJM Reliability Assurance Agreement: \n \n“Reliability Assurance Agreement” or “PJM Reliability Assurance Agreement” shall mean that \ncertain Reliability Assurance Agreement Among Load Serving Entities in the PJM Region, on \nfile with FERC as PJM Interconnection L.L.C. Rate Schedule FERC No. 44, and as amended \nfrom time to time thereafter. \n \nReliability Pricing Model Auction: \n \n“Reliability Pricing Model Auction” or “RPM Auction” shall mean the Base Residual Auction or \nany Incremental Auction. \n \nRequired Transmission Enhancements: \n \n“Regional Transmission Enhancements” shall mean enhancements and expansions of the \nTransmission System that (1) a Regional Transmission Expansion Plan developed pursuant to \nOperating Agreement, Schedule 6 or (2) any joint planning or coordination agreement between \nPJM and another region or transmission planning authority set forth in Tariff, Schedule 12-\nAppendix B (“Appendix B Agreement”) designates one or more of the Transmission Owner(s) to \nconstruct and own or finance.  Required Transmission Enhancements shall also include \nenhancements and expansions of facilities in another region or planning authority that meet the \ndefinition of transmission facilities pursuant to FERC’s Uniform System of Accounts or have \nbeen classified as transmission facilities in a ruling by FERC addressing such facilities \nconstructed pursuant to an Appendix B Agreement cost responsibility for which has been \nassigned at least in part to PJM pursuant to such Appendix B Agreement.  \n \nReserved Capacity: \n \n“Reserved Capacity” shall mean the maximum amount of capacity and energy that the \nTransmission Provider agrees to transmit for the Transmission Customer over the Transmission \nProvider’s Transmission System between the Point(s) of Receipt and the Point(s) of Delivery \nunder Tariff, Part II.  Reserved Capacity shall be expressed in terms of whole megawatts on a \nsixty (60) minute interval (commencing on the clock hour) basis. \n \nReserve Penalty Factor: \n \n“Reserve Penalty Factor” shall mean the cost, in $/MWh, associated with being unable to meet a \nspecific reserve requirement in a Reserve Zone or Reserve Sub-zone.  A Reserve Penalty Factor \nwill be defined for each reserve requirement in a Reserve Zone or Reserve Sub-zone. \n \nReserve Sub-zone:"},{"page":53,"startToken":17129,"endToken":17498,"text":"“Reserve Sub-zone” shall mean any of those geographic areas wholly contained within a Reserve \nZone, consisting of a combination of a portion of one or more Control Zone(s) as designated by \nthe Office of the Interconnection in the PJM Manuals, relevant to provision of, and requirements \nfor, reserve service. \n \nReserve Zone: \n \n“Reserve Zone” shall mean any of those geographic areas consisting of a combination of one or \nmore Control Zone(s), as designated by the Office of the Interconnection in the PJM Manuals, \nrelevant to provision of, and requirements for, reserve service. \n \nResidual Auction Revenue Rights: \n \n“Residual Auction Revenue Rights” shall mean incremental stage 1 Auction Revenue Rights \ncreated within a Planning Period by an increase in transmission system capability, including the \nreturn to service of existing transmission capability, that was not modeled pursuant to Operating \nAgreement, Schedule 1, section 7.5 and the parallel provisions of  Tariff, Attachment K-\nAppendix, section 7.5 in compliance with Operating Agreement, Schedule 1, section 7.4.2 (h) \nand the parallel provisions of Tariff, Attachment K-Appendix, section 7.4.2(h), and, if modeled, \nwould have increased the amount of stage 1 Auction Revenue Rights allocated pursuant to \nOperating Agreement, Schedule 1, section 7.4.2 and the parallel provisions of Tariff, Attachment \nK-Appendix, section 7.4.2; provided that, the foregoing notwithstanding, Residual Auction \nRevenue Rights shall exclude: 1) Incremental Auction Revenue Rights allocated pursuant to \nTariff, Part VI;  and 2) Auction Revenue Rights allocated to entities that are assigned cost \nresponsibility pursuant to Operating Agreement, Schedule 6 for  transmission upgrades that \ncreate such rights. \n \nResidual Metered Load: \n \n“Residual Metered Load” shall mean all load remaining in an electric distribution company’s \nfully metered franchise area(s) or service territory(ies) after all nodally priced load of entities \nserving load in such area(s) or territory(ies) has been carved out. \n \nResource Substitution Charge: \n \n“Resource Substitution Charge” shall mean a charge assessed on Capacity Market Buyers in an \nIncremental Auction to recover the cost of replacement Capacity Resources. \n \nRestricted Collateral: \n \n“Restricted Collateral” shall mean Collateral, held by PJM or PJMSettlement, which cannot be \nused, netted, credited or spent by the Participant to satisfy any other obligations. \n \nRevenue Data for Settlements:"},{"page":54,"startToken":17498,"endToken":17817,"text":"“Revenue Data for Settlements” shall mean energy quantities used in accounting and billing as \ndetermined pursuant to Tariff, Attachment K-Appendix and the corresponding provisions of \nOperating Agreement, Schedule 1. \n \nRPM Seller Credit: \n  \n“RPM Seller Credit” shall mean an additional form of Unsecured Credit defined in Tariff, \nAttachment Q, section VI. \n \nScheduled Incremental Auctions: \n \n“Scheduled Incremental Auctions” shall refer to the First, Second, or Third Incremental Auction. \n \nSchedule of Work: \n \n“Schedule of Work” shall mean that schedule attached to the Interconnection Construction \nService Agreement setting forth the timing of work to be performed by the Constructing Entity \npursuant to the Interconnection Construction Service Agreement, based upon the Facilities Study \nand subject to modification, as required, in accordance with Transmission Provider’s scope \nchange process for interconnection projects set forth in the PJM Manuals. \n \nScope of Work: \n \n“Scope of Work” shall mean that scope of the work attached as a schedule to the Interconnection \nConstruction Service Agreement and to be performed by the Constructing Entity(ies) pursuant to \nthe Interconnection Construction Service Agreement, provided that such Scope of Work may be \nmodified, as required, in accordance with Transmission Provider’s scope change process for \ninterconnection projects set forth in the PJM Manuals. \n \nSeasonal Capacity Performance Resource: \n \n“Seasonal Capacity Performance Resource” shall have the same meaning specified in Tariff, \nAttachment DD, section 5.5A. \n \nSecondary Reserve:  \n \n“Secondary Reserve” shall mean the reserve capability of generation resources that can be \nconverted fully into energy or Economic Load Response Participant resources whose demand can \nbe reduced within 30 minutes (less the capability of such resources to provide Primary Reserve), \nfrom the request of the Office of the Interconnection, regardless of whether the equipment \nproviding the reserve is electrically synchronized to the Transmission System or not. \n \nSecondary Systems: \n \n“Secondary Systems” shall mean control or power circuits that operate below 600 volts, AC or \nDC, including, but not limited to, any hardware, control or protective devices, cables, conductors,"},{"page":55,"startToken":17817,"endToken":18207,"text":"electric raceways, secondary equipment panels, transducers, batteries, chargers, and voltage and \ncurrent transformers. \n \nSecond Incremental Auction: \n \n“Second Incremental Auction” shall mean an Incremental Auction conducted ten months before \nthe Delivery Year to which it relates.   \n \nSecurity: \n \n“Security” shall mean the security provided by the New Service Customer pursuant to Tariff, \nsection 212.4 or Tariff, Part VI, section 213.4 to secure the New Service Customer’s responsibility \nfor Costs under the Interconnection Service Agreement or Upgrade Construction Service \nAgreement and Tariff, Part VI, section 217.  \n \nSegment:  \n“Segment” shall have the same meaning as described in Operating Agreement, Schedule 1, \nsection 3.2.3(e), and the parallel provisions of Tariff, Attachment K-Appendix, section 3.2.3(e). \n \nSelf-Supply: \n \n“Self-Supply” shall mean Capacity Resources secured by a Load-Serving Entity, by ownership \nor contract, outside a Reliability Pricing Model Auction, and used to meet obligations under this \nAttachment or the Reliability Assurance Agreement through submission in a Base Residual \nAuction or an Incremental Auction of a Sell Offer indicating such Market Seller’s intent that \nsuch Capacity Resource be Self-Supply.  Self-Supply may be either committed regardless of \nclearing price or submitted as a Sell Offer with a price bid. A Load Serving Entity's Sell Offer \nwith a price bid for an owned or contracted Capacity Resource shall not be deemed “Self-\nSupply,” unless it is designated as Self-Supply and used by the LSE to meet obligations under \nthis Attachment or the Reliability Assurance Agreement. \n \nSelf-Supply Entity: \n \n“Self-Supply Entity” shall mean the following types of Load Serving Entity that operate under \nlong-standing business models: single customer entity, public power entity, or vertically \nintegrated utility, where “vertically integrated utility” means a utility that owns generation, \nincludes such generation in its regulated rates, and earns a regulated return on its investment in \nsuch generation or receives any cost recovery for such generation through bilateral contracts; \n“single customer entity”  means a Load Serving Entity that serves at retail only customers that \nare under common control with such Load Serving Entity, where such control means holding \n51% or more of the voting securities or voting interests of the Load Serving Entity and all its \nretail customers; and “public power entity” means cooperative and municipal utilities, including \npublic power supply entities comprised of either or both of the same and rural electric \ncooperatives, and joint action agencies. \n \nSelf-Supply Seller:"},{"page":56,"startToken":18207,"endToken":18509,"text":"“Self-Supply Seller” shall mean, for purposes of evaluating Buyer-Side Market Power, the \nfollowing types of Load Serving Entities that operate under long-standing business models: \nvertically integrated utility or public power entity, where “vertically integrated utility” means a \nutility that owns generation, includes such generation in its state-regulated rates, and earns a \nstate-regulated return on its investment in such generation; and “public power entity” means \nelectric cooperatives that are either rate regulated by the state or have their long-term resource \nplan approved or otherwise reviewed and accepted by a Relevant Electric Retail Regulatory \nAuthority and municipal utilities or joint action agencies that are subject to direct regulation by a \nRelevant Electric Retail Regulatory Authority. \n \nSell Offer: \n \n“Sell Offer” shall mean an offer to sell Capacity Resources in a Base Residual Auction, \nIncremental Auction, or Reliability Backstop Auction. \n \nService Agreement: \n \n“Service Agreement” shall mean the initial agreement and any amendments or supplements thereto \nentered into by the Transmission Customer and the Transmission Provider for service under the \nTariff. \n \nService Commencement Date: \n \n“Service Commencement Date” shall mean the date the Transmission Provider begins to provide \nservice pursuant to the terms of an executed Service Agreement, or the date the Transmission \nProvider begins to provide service in accordance with Tariff, Part II, section 15.3 or Tariff, Part \nIII, section 29.1. \n \nShort-Term Firm Point-To-Point Transmission Service: \n \n“Short-Term Firm Point-To-Point Transmission Service” shall mean Firm Point-To-Point \nTransmission Service under Tariff, Part II with a term of less than one year. \n \nShort-term Project: \n \n“Short-term Project” shall have the same meaning provided in the Operating Agreement. \n \nSite: \n \n“Site” shall mean all of the real property, including but not limited to any leased real property and \neasements, on which the Customer Facility is situated and/or on which the Customer \nInterconnection Facilities are to be located. \n \nSmall Commercial Customer:"},{"page":57,"startToken":18509,"endToken":18836,"text":"“Small Commercial Customer,” as used in RAA, Schedule 6 and Tariff, Attachment DD-1, shall \nmean a commercial retail electric end-use customer of an electric distribution company that \nparticipates in a mass market demand response program under the jurisdiction of a RERRA and \nsatisfies the definition of a “small commercial customer” under the terms of the applicable \nRERRA’s program, provided that the customer has an annual peak demand no greater than \n100kW. \n \nSmall Generation Resource: \n \n“Small Generation Resource” shall mean an Interconnection Customer’s device of 20 MW or less \nfor the production and/or storage for later injection of electricity identified in an Interconnection \nRequest, but shall not include the Interconnection Customer’s Interconnection Facilities.  This \nterm shall include Energy Storage Resources and/or other devices for storage for later injection of \nenergy. \n \nSmall Inverter Facility: \n \n“Small Inverter Facility” shall mean an Energy Resource that is a certified small inverter-based \nfacility no larger than 10 kW. \n \nSmall Inverter ISA: \n \n“Small Inverter ISA” shall mean an agreement among Transmission Provider, Interconnection \nCustomer, and Interconnected Transmission Owner regarding interconnection of a Small Inverter \nFacility under Tariff, Part IV, section 112B. \n \nSpecial Member: \n \n “Special Member” shall mean an entity that satisfies the requirements of Operating Agreement, \nSchedule 1, section 1.5A.02, and the parallel provisions of Tariff, Attachment K-Appendix, \nsection 1.5A.02, or the special membership provisions established under the Emergency Load \nResponse and Pre-Emergency Load Response Programs. \n \nSpot Market Backup: \n \n“Spot Market Backup” shall mean the purchase of energy from, or the delivery of energy to, the \nPJM Interchange Energy Market in quantities sufficient to complete the delivery or receipt \nobligations of a bilateral contract that has been curtailed or interrupted for any reason. \n \nSpot Market Energy: \n \n“Spot Market Energy” shall mean energy bought or sold by Market Participants through the PJM \nInterchange Energy Market at System Energy Prices determined as specified in Operating \nAgreement, Schedule 1, section 2, and the parallel provisions of Tariff, Attachment K-Appendix, \nsection 2."},{"page":58,"startToken":18836,"endToken":19206,"text":"Start Additional Labor Costs: \n \n“Start Additional Labor Costs” shall mean additional labor costs for startup required above \nnormal station manning levels.  \n \nStart Fuel: \n \nFor units without a soak process, “Start Fuel” shall consist of fuel consumed from first fire of the \nstart process to first breaker closing, plus any fuel expended from last breaker opening to \nshutdown. \n \nFor units with a soak process, “Start Fuel” is fuel consumed from first fire of the start process \n(initial reactor criticality for nuclear units) to dispatchable output (including auxiliary boiler \nfuel), plus any fuel expended from last breaker opening to shutdown, excluding normal plant \nheating/auxiliary equipment fuel requirements.  Start Fuel included for each temperature state \nfrom breaker closure to dispatchable output shall not exceed the unit specific soak time period \nreviewed and approved as part of the unit-specific parameter process detailed in Tariff, \nAttachment K-Appendix, section 6.6(c) or the defaults below: \n• Cold Soak Time = 0.73 * unit specific Minimum Run Time (in hours) \n• Intermediate Soak Time = 0.61 * unit specific Minimum Run Time (in hours) \n• Hot Soak Time = 0.43 * unit specific Minimum Run Time (in hours)   \n \nStart-Up Costs: \n \n“Start-Up Costs” shall consist primarily of the cost of fuel, as determined by the unit’s start heat \ninput (adjusted by the performance factor) times the fuel cost.  It also includes operating costs, \nMaintenance Adders, emissions allowances/adders, and station service cost.  Start-Up Costs can \nvary with the unit offline time being categorized in three unit temperature conditions: hot, \nintermediate and cold. \n \nFor units with a steam turbine and a soak process (nuclear, steam, and combined cycle), “Start \nFuel” is fuel consumed from first fire of start process (initial reactor criticality for nuclear units): \nStart-Up Costs shall mean the net unit costs from PJM’s notification to the level at which the unit \ncan follow PJM’s dispatch, and from last breaker open to shutdown. \n \nFor units without a steam turbine and no soak process (engines, combustion turbines, Intermittent \nResources, and Energy Storage Resources): Start-Up Costs shall mean the unit costs from PJM’s \nnotification to first breaker close and from last breaker open to shutdown.   \n \nState: \n \n“State” shall mean the District of Columbia and any State or Commonwealth of the United States. \n \nState Commission:"},{"page":59,"startToken":19206,"endToken":19648,"text":"“State Commission” shall mean any state regulatory agency having jurisdiction over retail \nelectricity sales in any State in the PJM Region. \n \nState Estimator: \n \n“State Estimator” shall mean the computer model of power flows specified in Operating \nAgreement, Schedule 1, section 1.11A and the parallel provisions of Tariff, Attachment K-\nAppendix, section 1.11A. \n \nState of Charge: \n \n“State of Charge” shall mean the operating parameter that represents the quantity of physical \nenergy stored (measured in units of megawatt-hours) in an Energy Storage Resource Model \nParticipant or in a storage component of a Hybrid Resource in proportion to its maximum State \nof Charge capability. State of Charge is quantified as defined in the PJM Manuals. \n \nState of Charge Management: \n \n“State of Charge Management” shall mean the control of State of Charge of an Energy Storage \nResource Market Participant or a storage component of a Hybrid Resource using Charge and \nDischarge Economic Minimum and Maximum Megawatts (and, as applicable, charge) limits, \nchanges in operating mode (as applicable), discharging (and, as applicable, charging) offer \ncurves, and self-scheduling of non-dispatchable sales (and, as applicable, purchases) of energy in \nthe PJM markets.  State of Charge Management shall not interfere with the obligation of a \nMarket Seller of an Energy Storage Resource Model Participant or of a Hybrid Resource to \nfollow PJM dispatch, consistent with all other resources. \n \nState Subsidy: \n \n“State Subsidy” shall mean a direct or indirect payment, concession, rebate, subsidy, non-\nbypassable consumer charge, or other financial benefit that is as a result of any action, mandated \nprocess, or sponsored process of a state government, a political subdivision or agency of a state, \nor an electric cooperative formed pursuant to state law, and that  \n(1) is derived from or connected to the procurement of (a) electricity or electric generation \ncapacity sold at wholesale in interstate commerce, or (b) an attribute of the generation \nprocess for electricity or electric generation capacity sold at wholesale in interstate \ncommerce; or \n(2) will support the construction, development, or operation of a new or existing Capacity \nResource; or  \n(3) could have the effect of allowing the unit to clear in any PJM capacity auction.  \nNotwithstanding the foregoing, State Subsidy shall not include (a) payments, concessions, \nrebates, subsidies, or incentives designed to incent, or participation in a program, contract or \nother arrangement that utilizes criteria designed to incent or promote, general industrial \ndevelopment in an area or designed to incent siting facilities in that county or locality rather than \nanother county or locality; (b) state action that imposes a tax or assesses a charge utilizing the \nparameters of a regional program on a given set of resources notwithstanding the tax or cost"},{"page":60,"startToken":19648,"endToken":20200,"text":"having indirect benefits on resources not subject to the tax or cost (e.g., Regional Greenhouse \nGas Initiative); (c) any indirect benefits to a Capacity Resource as a result of any transmission \nproject approved as part of the Regional Transmission Expansion Plan; (d) any contract, legally \nenforceable obligation, or rate pursuant to the Public Utility Regulatory Policies Act or any other \nstate-administered federal regulatory program (e.g., the Cross-State Air Pollution Rule); (e) any \nrevenues from the sale or allocation, either direct or indirect, to an Entity Providing Supply \nServices to Default Retail Service Provider where such entity’s obligations was awarded through \na state default procurement auction that was subject to independent oversight by a consultant or \nmanager who certifies that the auction was conducted through a non-discriminatory and \ncompetitive bidding process, subject to the below condition, and provided further that nothing \nherein would exempt a Capacity Resource that would otherwise be subject to the minimum offer \nprice rule pursuant to this Tariff; (f) any revenues for providing capacity as part of an FRR \nCapacity Plan or through bilateral transactions with FRR Entities; or (g) any voluntary and arm’s \nlength bilateral transaction (including but not limited to those reported pursuant to Tariff, \nAttachment DD, section 4.6), such as a power purchase agreement or other similar contract \nwhere the buyer is a Self-Supply Entity and the transaction is (1) a short term transaction (one-\nyear or less) or (2) a long-term transaction that is the result of a competitive process that was not \nfuel-specific and is not used for the purpose of supporting uneconomic construction, \ndevelopment, or operation of the subject Capacity Resource, provided however that if the Self-\nSupply Entity is responsible for offering the Capacity Resource into an RPM Auction, the \nspecified amount of installed capacity purchased by such Self-Supply Entity shall be considered \nto receive a State Subsidy in the same manner, under the same conditions, and to the same extent \nas any other Capacity Resource of a Self-Supply Entity.  For purposes of subsection (e) of this \ndefinition, a state default procurement auction that has been certified to be a result of a non-\ndiscriminatory and competitive bidding process shall: \n(i) \nhave no conditions based on the ownership (except supplier diversity \nrequirements or limits), location (except to meet PJM deliverability \nrequirements), affiliation, fuel type, technology, or emissions of any resources or \nsupply (except state-mandated renewable portfolio standards for which Capacity \nResources are separately subject to the minimum offer price rule or eligible for an \nexemption); \n(ii) \nresult in contracts between an Entity Providing Supply Services to Default Retail \nService Provider and the electric distribution company for a retail default \ngeneration supply product and none of those contracts require that the retail \nobligation be sourced from any specific Capacity Resource or resource type as set \nforth in subsection (i) above; and \n(iii) \nestablish market-based compensation for a retail default generation supply \nproduct that retail customers can avoid paying for by obtaining supply from a \ncompetitive retail supplier of their choice. \n \n \nStation Power: \n \n“Station Power” shall mean energy used for operating the electric equipment on the site of a \ngeneration facility located in the PJM Region or for the heating, lighting, air-conditioning and \noffice equipment needs of buildings on the site of such a generation facility that are used in the"},{"page":61,"startToken":20200,"endToken":20507,"text":"operation, maintenance, or repair of the facility.  Station Power does not include any energy (i) \nused to power synchronous condensers; (ii) used for pumping at a pumped storage facility; (iii) \nused in association with restoration or black start service; or (iv) that is Direct Charging Energy. \n \nSub-meter: \n \n“Sub-meter” shall mean a metering point for electricity consumption that does not include all \nelectricity consumption for the end-use customer as defined by the electric distribution company \naccount number.  PJM shall only accept sub-meter load data from end-use customers for \nmeasurement and verification of Regulation service as set forth in the Economic Load Response \nrules and PJM Manuals. \n \nSummer-Period Capacity Performance Resource: \n \n“Summer-Period Capacity Performance Resource” shall have the same meaning specified in \nTariff, Attachment DD, section 5.5A. \n \nSurplus Interconnection Customer: \n \n“Surplus Interconnection Customer” shall mean either an Interconnection Customer whose \nGenerating Facility is already interconnected to the PJM Transmission System or one of its \naffiliates, or an unaffiliated entity that submits a Surplus Interconnection Request to utilize \nSurplus Interconnection Service within the Transmission System in the PJM Region.  A Surplus \nInterconnection Customer is not a New Service Customer.    \n \nSurplus Interconnection Request: \n \n“Surplus Interconnection Request” shall mean a request submitted by a Surplus Interconnection \nCustomer, pursuant to Tariff, Attachment RR, to utilize Surplus Interconnection Service within \nthe Transmission System in the PJM Region.  A Surplus Interconnection Request is not a New \nService Request. \n \nSurplus Interconnection Service: \n \n“Surplus Interconnection Service” shall mean any unneeded portion of Interconnection Service \nestablished in an Interconnection Service Agreement, such that if Surplus Interconnection Service \nis utilized, the total amount of Interconnection Service at the Point of Interconnection would \nremain the same. \n \nSwitching and Tagging Rules: \n \n“Switching and Tagging Rules” shall mean the switching and tagging procedures of \nInterconnected Transmission Owners and Interconnection Customer as they may be amended \nfrom time to time.  \n \nSynchronized Reserve:"},{"page":62,"startToken":20507,"endToken":20887,"text":"“Synchronized Reserve” shall mean the reserve capability of generation resources that can be \nconverted fully into energy or Economic Load Response Participant resources whose demand \ncan be reduced within ten minutes from the request of the Office of the Interconnection \ndispatcher, and is provided by equipment that is electrically synchronized to the Transmission \nSystem. \n \nSynchronized Reserve Event: \n \n“Synchronized Reserve Event” shall mean a request from the Office of the Interconnection to \ngeneration resources and/or Economic Load Response Participant resources able, assigned or \nself-scheduled to provide Synchronized Reserve in one or more specified Reserve Zones or \nReserve Sub-zones, within ten minutes, to increase the energy output or reduce load by a \ndirected amount of the assigned or self-scheduled Synchronized Reserve. \n \nSynchronized Reserve Requirement: \n \n“Synchronized Reserve Requirement” shall mean the megawatts required to be maintained in a \nReserve Zone or Reserve Sub-zone as Synchronized Reserve, absent any increase to account for \nadditional reserves scheduled to address operational uncertainty.  The Synchronized Reserve \nRequirement is calculated in accordance with the PJM Manuals.  This requirement can only be \nsatisfied by Synchronized Reserve resources. \n \nSystem Condition: \n \n“System Condition” shall mean a specified condition on the Transmission Provider’s system or on \na neighboring system, such as a constrained transmission element or flowgate, that may trigger \nCurtailment of Long-Term Firm Point-to-Point Transmission Service using the curtailment \npriority pursuant to Tariff, Part II, section 13.6.  Such conditions must be identified in the \nTransmission Customer’s Service Agreement. \n \nSystem Energy Price: \n \n“System Energy Price” shall mean the energy component of the Locational Marginal Price, \nwhich is the price at which the Market Seller has offered to supply an additional increment of \nenergy from a resource, calculated as specified in Operating Agreement, Schedule 1, section 2 \nand the parallel provisions of Tariff, Attachment K-Appendix, section 2. \n \nSystem Impact Study: \n \n“System Impact Study” shall mean an assessment by the Transmission Provider of (i) the adequacy \nof the Transmission System to accommodate a Completed Application, an Interconnection \nRequest or an Upgrade Request, (ii) whether any additional costs may be incurred in order to \nprovide such transmission service or to accommodate an Interconnection Request, and (iii) with \nrespect to an Interconnection Request, an estimated date that an Interconnection Customer’s \nCustomer Facility can be interconnected with the Transmission System and an estimate of the"},{"page":63,"startToken":20887,"endToken":21067,"text":"Interconnection Customer’s cost responsibility for the interconnection; and (iv) with respect to an \nUpgrade Request, the estimated cost of the requested system upgrades or expansion, or of the cost \nof the system upgrades or expansion, necessary to provide the requested incremental rights. \n \nSystem Protection Facilities: \n \n“System Protection Facilities” shall refer to the equipment required to protect (i) the Transmission \nSystem, other delivery systems and/or other generating systems connected to the Transmission \nSystem from faults or other electrical disturbance occurring at or on the Customer Facility, and (ii) \nthe Customer Facility from faults or other electrical system disturbance occurring on the \nTransmission System or on other delivery systems and/or other generating systems to which the \nTransmission System is directly or indirectly connected.  System Protection Facilities shall include \nsuch protective and regulating devices as are identified in the Applicable Technical Requirements \nand Standards or that are required by Applicable Laws and Regulations or other Applicable \nStandards, or as are otherwise necessary to protect personnel and equipment and to minimize \ndeleterious effects to the Transmission System arising from the Customer Facility."},{"page":64,"startToken":21067,"endToken":21467,"text":"5.5 \nEligibility for Participation in RPM Auctions \n \n(a) \nA Capacity Market Seller may submit a Sell Offer for a Capacity Resource in a Base \nResidual Auction or Incremental Auction only if such seller owns or has the contractual authority \nto control the output or load reduction capability of such resource and has not transferred such \nauthority to another entity prior to submitting such Sell Offer. Capacity Resources must satisfy \nthe capability and deliverability requirements of RAA, Schedule 9 and RAA, Schedule 10, the \nrequirements for Demand Resources or Energy Efficiency Resources in Tariff, Attachment DD-\n1 and RAA, Schedule 6, as applicable, and, the criteria in Tariff, Attachment DD, section 5.5A. \nA Planned Generation Capacity Resource may be included in a Sell Offer for an RPM Auction \nonly if the Capacity Market Seller of such resource provides a binding notice of intent, as further \ndetailed in the PJM Manuals, to submit a Sell Offer in such auction to the Office of the \nInterconnection no later than (a) the immediately preceding December 1 for a Base Residual \nAuction, or (b) ninety (90) days prior to the commencement of the offer period for an Incremental \nAuction.   \n \n(b) \nNotwithstanding the foregoing, a committed RBP Resource shall be required to be offered \ninto the relevant Base Residual Auction and is not required to submit a binding notice of intent to \noffer into such auction.  However, a committed RBP Resource that is not the subject of a notice of \nintent to be offered into the Base Residual Auction associated with the 2029/2030 Delivery Year \nshall be offered into the Second Incremental Auction for the 2029/2030 Delivery Year. In the event \na committed RBP Resource is not expected to be in-service or deliverable by the relevant Delivery \nYear, the Capacity Market Seller of such committed RBP Resource may notify the Office of the \nInterconnection, with supporting documentation, that the resource is not expected to be in-service \nor deliverable by the relevant Delivery Year. Such notice for a committed RBP Resource shall be \nsubmitted no later than (i) the immediately preceding December 1 for a Base Residual Auction or \n(ii) ninety (90) days prior to the commencement of the offer period for an Incremental Auction. A \ncommitted RBP Resource that provides such notice will be assessed any applicable RBP shortfall \ncharge and not be allowed to be offered into the applicable RPM Auction."},{"page":65,"startToken":21467,"endToken":21988,"text":"5.5A Capacity Resource Types \n \n(a) \nCapacity Performance Resources \n \nCapacity Performance Resources are Capacity Resources which, to the extent such resources \ncleared in a Reliability Pricing Model Auction or are otherwise committed as a Capacity \nResource, are obligated to deliver energy during the relevant Delivery Year as scheduled and/or \ndispatched by the Office of Interconnection during the Performance Assessment Intervals.  As \nfurther detailed in Tariff, Attachment DD, section 10A, Capacity Performance Resources that \nfail to meet this obligation will be subject to a Non-Performance Charge, unless excused \npursuant to Tariff, Attachment DD, section 10A(d).  As further detailed in Tariff, Attachment \nDD, section 10B, Demand Resources that fail to meet this obligation during Non-PAI Events \nwill be subject to a Non-Curtailment Charge.  Subject to 5.5A(a)(i), the following types of \nCapacity Resources are eligible to submit a Sell Offer as a Capacity Performance Resource: \ninternal or external Generation Capacity Resources; Annual Demand Resources; Capacity \nStorage Resources; Annual Energy Efficiency Resources; and Qualifying Transmission \nUpgrades.  To the extent the underlying Capacity Resource is an external Generation Capacity \nResource, such resource must meet, to the extent subsection (b) or (c) of this section is applicable \nto offers from such resource, meet the applicable requirements of such subsection, and if neither \nsubsection (b) or (c) is applicable, then offers from such resource must the criteria for obtaining \nan exception to the Capacity Import Limit as contained in RAA, Article 1.  However, Electrical \nDistance requirements shall not apply to an external Generation Capacity Resource to the extent \nthat such resource is an RBP Resource committed through the Reliability Backstop Procurement \nthat is subsequently pseudo-tied to the PJM Region to the extent the Office of the \nInterconnection has elected to retain the resource, for the remainder of its RBP commitment \nterm, within the PJM Region after the relevant Transmission Owner has exited PJM \nInterconnection, L.L.C. pursuant to Tariff, Attachment DD, section 18.7(a). \n \n(i) \nProcess for Support and Review of Capacity Performance Resource Offers    \n \nA. \nThe Capacity Market Seller shall provide to the Office of the \nInterconnection and the Market Monitoring Unit, upon their request, all supporting data \nand information requested by either the Office of the Interconnection or the Market \nMonitoring Unit to evaluate whether the underlying Capacity Resource can meet the \noperational and performance requirements of Capacity Performance Resources.  The \nCapacity Market Seller shall have an ongoing obligation through the closing of the offer \nperiod for the RPM Auction to update the request to reflect any material changes. \n \nB. \nThe Office of the Interconnection and the Market Monitoring Unit shall \nreview any requested supporting data and information, and the Office of the \nInterconnection, considering advice and recommendation from the Market Monitoring \nUnit, shall reject a request for a resource to offer as a Capacity Performance Resource if \nthe Capacity Market Seller does not demonstrate that it can reasonably be expected to \nmeet its Capacity Performance obligations consistent with the resource’s offer by the \nrelevant Delivery Year.  The Office of Interconnection shall provide its determination to \nreject eligibility of the resource as a Capacity Performance Resource, and notify the"},{"page":66,"startToken":21988,"endToken":22422,"text":"Market Monitoring Unit, by no later than sixty-five (65) days prior to the date on which \nthe offer period for the applicable RPM Auction commences.  A Capacity Market Seller \nthat is dissatisfied with any determination hereunder may seek any remedies available to \nit from FERC; provided, however, that the Office of the Interconnection will proceed \nwith administration of the Tariff and market rules unless and until ordered to do \notherwise by FERC.  \n \n(b) \nOffers from External Generation Capacity Resources for the 2020/2021 Delivery Year \nand Subsequent Delivery Years—General Rule \n \nFor the 2020/2021 Delivery Year and any subsequent Delivery Year and for Capacity \nPerformance Resource Sell Offers in any RPM Auction conducted for the 2018/2019 Delivery \nYear or 2019/2020 Delivery Year after May 9, 2017, unless excepted pursuant to subsection (c) \nbelow, a Capacity Market Seller may submit a Sell Offer for an external Generation Capacity \nResource in an RPM Auction if the Capacity Market Seller demonstrates to PJM, by no later \nthan five (5) business days prior to the commencement of the offer period for the relevant RPM \nAuction, that such resource meets all of the following requirements: \n(i)  \nThe Capacity Market Seller has obtained a determination that the Pseudo-Tie \nrequired for its external Generation Capacity Resource is feasible, including (without limitation) \nthat such Pseudo-Tie meets the following requirements: \n \n(A) the external Generation Capacity Resource must have a minimum Electrical \nDistance impedance equal to or less than 0.065 p.u.; or is within one station of a \ntransmission bus that has a minimum Electrical Distance impedance equal to or less than \n0.065 p.u.  With regard to this Electrical Distance requirement, the Office of the \nInterconnection shall:  \n \n(1) post on its website the material assumptions, applicable to all tested \ngenerators, implemented in the modeling software used to conduct the \nElectrical Distance analysis (e.g., the general process used to define \nthe facilities included in the Electrical Distance requirement and \nanalysis for each Pseudo-Tie applicant);  \n \n(2) upon  request by an applicant for a Pseudo-Tie, provide that applicant \na copy of the results of the Electrical Distance analysis conducted by \nthe Office of the Interconnection for the specific Pseudo-Tie requested \nby the applicant, as well as related work papers; and \n \n (3) upon request by an applicant for a Pseudo-Tie, meet with that \napplicant to discuss specific modeling assumptions and the results of \nthe Electrical Distance analysis for the specific Pseudo-Tie requested \nby that applicant; \n \n \n(B) at least one generation resource that has a historic economic minimum offer \nlower than its historic economic maximum offer, located inside the metered boundaries"},{"page":67,"startToken":22422,"endToken":22842,"text":"of the PJM Region, has a minimum flow distribution impact of 1.5 percent on each \neligible coordinated flowgate resulting from such Pseudo-Tie.  With regard to this \nrequirement, the Office of the Interconnection shall:  \n \n(1) post on its website the material assumptions, applicable to all tested \ngenerators, that have been implemented in the modeling software used \nto conduct the analysis to determine whether the requirement has been \nmet (e.g., the definitions of the sink and source used in the market-to-\nmarket analysis and the definition of eligible coordinated flowgates as \napplicable to the requirement);  \n \n(2) upon request by an applicant for a Pseudo-Tie, provide that applicant a \ncopy of the results of the market-to-market flowgate analysis conducted by \nthe Office of the Interconnection for the specific Pseudo-Tie requested by \nthe applicant, as well as related work papers;  and \n \n(3) upon request by an applicant for a Pseudo-Tie, meet with that applicant \nto discuss specific modeling assumptions and the results of the market-to-\nmarket flowgate analysis conducted for the specific Pseudo-Tie requested \nby that applicant;  \n \n \n(C) each external  entity with which PJM may be required to coordinate flowgates \nunder an agreed congestion management process maintains a network model that \nproduces results for such flowgates that are within two percent of the results produced by \nthe PJM network model for such flowgates;   \n \n(D) the Capacity Market Seller has secured written acknowledgement from the \nexternal Balancing Authority Areas that such Pseudo-Tie does not require tagging and \nthat firm allocations associated with any coordinated flowgates applicable to the external \nGeneration Capacity Resource under any agreed congestion management process then in \neffect between PJM and such Balancing Authority Area will be allocated to PJM.  \n \nand the Capacity Market Seller has committed in writing that it will take all steps necessary to \nimplement such Pseudo-Tie prior to the start of the relevant Delivery Year; \n \n(ii)  \nit has, for transmission outside PJM, obtained long-term firm point-to-point \ntransmission service (evaluated for deliverability from the unit-specific physical location of the \nresource to PJM load pursuant to a study that is reviewed and approved by PJM in accordance \nwith PJM deliverability criteria to ensure uniformity for internal and external resource \ndeliverability requirements), with rollover rights for the term of the transmission service that is \nconfirmed by the Balancing Authority for the Balancing Authority Area where such resource is \ngeographically located; and, as to transmission within PJM, has obtained Network External \nDesignated Transmission Service; and \n \n(iii) \nit is, by written commitment of the Capacity Market Seller, subject to the same"},{"page":68,"startToken":22842,"endToken":23341,"text":"obligations imposed on Generation Capacity Resources located in the PJM Region by Tariff, \nAttachment DD, section 6.6 to offer their capacity into RPM Auctions. \n \nA Capacity Market Seller that satisfies the above requirements with respect to an external \nGeneration Capacity Resource Sell Offer submitted in an RPM Auction for a Delivery Year shall \nbe required to demonstrate satisfaction of such requirements for any Sell Offer with respect to \nsuch resource submitted in an RPM Auction for any subsequent Delivery Year, including, \nwithout limitation, demonstration that the required external transmission service continues to \nsatisfy PJM’s deliverability standards. \n \n \n \n(c) \nOffers from external Generation Capacity Resources for the 2020/2021 Delivery Year \nand Subsequent Delivery Years—Exception. \n \nA Capacity Market Seller of a Prior CIL Exception External Resource may continue to submit \nSell Offers for such resource for any RPM Auction for any Delivery Year up to and including the \n2021/2022 Delivery Year (or, solely for any such resource that is (1) owned by a Load Serving \nEntity and used to self-supply (under arrangements initiated before June 1, 2016, with a duration \nof at least ten years) such entity’s PJM Region load or (2) the subject of a contract for energy or \ncapacity or equivalent written agreement entered into on or before June 1, 2016 for a term of ten \nyears or longer with a purchaser that is an internal PJM load customer, for any Delivery Year \nduring the life of such resource for subparagraph (1) or for the term of the agreement under \nsubparagraph (2)) so long as it continues to comply with all conditions on the grant of its \nexception to the Capacity Import Limit, subject to the following additional conditions:  \n \n(i) \nfor any Delivery Year, beginning with the 2017/2018 Delivery Year, for \nwhich such Prior CIL Exception External Resource has cleared an RPM Auction, PJM \nmay in its sole judgment determine that the resource is not Operationally Deliverable for \nsuch Delivery Year because it does not satisfy the requirements of subsection (b).  If PJM \ndetermines a Prior CIL Exception External Resource is not Operationally Deliverable for \na Delivery Year, it must notify the Capacity Market Seller of its determination by no later \nthan October 1 immediately preceding such Delivery Year.  After receiving such notice, \nthe Capacity Market Seller may elect to: \n \n (A) take the necessary actions to make the Prior CIL Exception External \nResource Operationally Deliverable, in PJM’s sole judgment, prior to the \nbeginning of such Delivery Year, provided that PJM will, if transmission \nupgrades are required to make such resource Operationally Deliverable, facilitate \nthe performance of transmission studies and otherwise cooperate with the external  \nTransmission Provider of the system on which such upgrades are required to \nidentify the upgrades required to meet PJM’s deliverability standards;  \n \n(B) be relieved of its capacity obligation for such Delivery Year by \nproviding written notice of such election to the Office of the Interconnection no \nlater than seven (7) days prior to the posting of planning parameters for the Third"},{"page":69,"startToken":23341,"endToken":23761,"text":"Incremental Auction for such Delivery Year as PJM will procure the replacement \ncapacity in the Third Incremental Auction in accordance with Tariff, Attachment \nDD, sections 5.12(b)(ii) and 5.12(b)(iii), with no entitlement to any capacity \nrevenues based on such resource, with no requirement to seek replacement for \nsuch capacity for such Delivery Year, with no penalty for non-performance or \nlack of commitment for such Delivery Year, and with no further must-offer \nobligation that would otherwise arise solely from clearing such capacity for such \nDelivery Year; or \n \n(C) procure, by purchase or otherwise, replacement in a sufficient quantity \nto replace the capacity that would have been provided by the Prior CIL Exception \nExternal Resource but for PJM’s determination that such resource is not \nOperationally Deliverable.  \n \n(ii) \nSuch Capacity Market Seller’s continued ability to offer such resource \nunder this exception is conditioned on external Transmission Providers continuing to \nhonor the firm status of the Capacity Market Seller’s transmission service for all Delivery \nYears for which such seller offers such resource under the exceptions provided in this \nsubsection (c). \n \n(iii) \nA Capacity Market Seller offering and clearing a Prior CIL Exception \nExternal Resource pursuant to this subsection (c) shall be relieved of its must-offer \nobligation that would otherwise arise solely from clearing such capacity.  Such relief of \nthe must-offer obligation shall be for any Delivery Year after the last Delivery Year for \nwhich it is permitted to offer such resource under this subsection (c). \n \n(iv)  \nPJM will determine key triggers for when a Prior CIL Exception External \nResource will not be Operationally Deliverable, including the need for: (1) a remedial \naction scheme or manual generation dump protocol to manage external transmission \nemergencies; (2) transmission facility switching arrangements that would have the effect \nof radializing load in order to manage external transmission emergencies; and (3) “out of \nmarket” external Balancing Authority or Transmission Operator directed dispatch \ninstructions to manage excessive or unacceptable frequency of external regional \nreliability limit violations or (outside an interregional agreed congestion management \nprocess) of local reliability limit violations. \n \n(d) \nSeasonal Capacity Performance Resource \nA Seasonal Capacity Performance Resource shall mean a Summer-Period Capacity Performance \nResource or Winter-Period Capacity Performance Resource, as defined below.  \n \ni) \nSummer-Period Capacity Performance Resource \nThe following types of Capacity Resources are eligible to submit a Sell Offer as a \nSummer-Period Capacity Performance Resource: Summer Period Demand Resource that \nhas an average expected energy output during summer peak-hour periods consistently \nand measurably greater than its average expected energy output during winter peakhour"},{"page":70,"startToken":23761,"endToken":24018,"text":"periods.  To the extent such resource clears an RPM Auction or is otherwise committed \nas a Summer-Period Capacity Performance Resource, it is obligated to reduce when \ndispatched by the Office of Interconnection during Performance Assessment Intervals or \nNon-PAI Event intervals occurring in the calendar months of June through October and \nthe following May of the Delivery Year, and must satisfy the requirements of a Capacity \nPerformance Resource for such period of time. As further detailed in Tariff, Attachment \nDD, sections 10A or 10B, Summer-Period Capacity Performance Resources that fail to \nmeet this obligation will be subject to a Non-Performance Charge, unless excused \npursuant to Tariff, Attachment DD, section 10A(d) and a Non-Curtailment Charge.   \n \nii) \nWinter-Period Capacity Performance Resource \n \nThe following types of Capacity Resources are eligible to submit a Sell Offer as a \nWinter-Period Capacity Performance Resource: Intermittent Resource that has been \ngranted additional Capacity Interconnection Rights related to the winter-period.  To the \nextent such resource clears an RPM Auction or is otherwise committed as a Winter-\nPeriod Capacity Performance Resource, it is obligated to deliver energy as scheduled \nand/or dispatched by the Office of Interconnection during Performance Assessment \nIntervals occurring in the calendar months of November through April of the Delivery \nYear, and must satisfy the requirements of a Capacity Performance Resource for such \nperiod of time.  As further detailed in Tariff, Attachment DD, section 10A, Winter-Period \nCapacity Performance Resources that fail to meet this obligation will be subject to a Non-\nPerformance Charge, unless excused pursuant to Tariff, Attachment DD, section 10A(d)."},{"page":71,"startToken":24018,"endToken":24548,"text":"5.14 \nClearing Prices and Charges \n \n \na) \nCapacity Resource Clearing Prices  \n \nFor each Base Residual Auction and Incremental Auction, the Office of the Interconnection shall \ncalculate a clearing price to be paid for each megawatt-day of Unforced Capacity that clears in \nsuch auction.  The Capacity Resource Clearing Price for each LDA will be the marginal value of \nsystem capacity for the PJM Region, without considering locational constraints, adjusted as \nnecessary by any applicable Locational Price Adders, all as determined by the Office of the \nInterconnection based on the optimization algorithm.   If a Capacity Resource is located in more \nthan one Locational Deliverability Area, it shall be paid the highest Locational Price Adder in \nany applicable LDA in which the Sell Offer for such Capacity Resource cleared.  \n \nThe Locational Price Adder applicable to each cleared Seasonal Capacity Performance Resource \nis determined during the post-processing of the RPM Auction results consistent with the manner \nin which the auction clearing algorithm recognizes the contribution of Seasonal Capacity \nPerformance Resource Sell Offers in satisfying an LDA’s reliability requirement.  For each LDA \nwith a positive Locational Price Adder with respect to the immediate higher level LDA, starting \nwith the lowest level constrained LDAs and moving up, PJM determines the quantity of equally \nmatched Summer-Period Capacity Performance Resources and Winter-Period Capacity \nPerformance Resources located and cleared within that LDA.  Up to this quantity, the cleared \nSummer-Period Capacity Performance Resources and Winter-Period Capacity Performance \nResources with the lowest Sell Offer prices will be compensated using the highest Locational \nPrice Adder applicable to such LDA; and any remaining Seasonal Capacity Performance \nResources cleared within the LDA are effectively moved to the next higher level constrained \nLDA, where they are considered in a similar manner for compensation. \n \n \nb) \nResource Make-Whole Payments \n \nIf a Sell Offer specifies a minimum block, and only a portion of such block is needed to clear the \nmarket in a Base Residual or Incremental Auction, the MW portion of such Sell Offer needed to \nclear the market shall clear, and such Sell Offer shall set the marginal value of system capacity.  \nIn addition, the Capacity Market Seller shall receive a Resource Make-Whole Payment equal to \nthe Capacity Resource Clearing Price in such auction times the difference between the Sell \nOffer's minimum block MW quantity and the Sell Offer's cleared MW quantity.  If the Sell Offer \nprice of a cleared Seasonal Capacity Performance Resource exceeds the applicable Capacity \nResource Clearing Price, the Capacity Market Seller shall receive a Resource Make-Whole \nPayment equal to the difference between the Sell Offer price and Capacity Resource Clearing \nPrice in such RPM Auction.  The cost for any such Resource Make-Whole Payments required in \na Base Residual Auction or Incremental Auction for adjustment of prior capacity commitments \nshall be collected pro rata from all LSEs in the LDA in which such payments were made, based \non their Daily Unforced Capacity Obligations. The cost for any such Resource Make-Whole \nPayments required in an Incremental Auction for capacity replacement shall be collected from all \nCapacity Market Buyers in the LDA in which such payments were made, on a pro-rata basis \nbased on the MWs purchased in such auction. \n \n \nc) \nNew Entry Price Adjustment"},{"page":72,"startToken":24548,"endToken":25068,"text":"A Capacity Market Seller that submits a Sell Offer based on a Planned Generation Capacity \nResource that clears in the BRA for a Delivery Year may, at its election, submit Sell Offers with \na New Entry Price Adjustment in the BRAs for the two immediately succeeding Delivery Years \nif: \n \n1. \nSuch Capacity Market Seller provides notice of such election at the time it \nsubmits its Sell Offer for such resource in the BRA for the first Delivery Year for which such \nresource is eligible to be considered a Planned Generation Capacity Resource.  When the \nCapacity Market Seller provides notice of such election, it must specify whether its Sell Offer is \ncontingent upon qualifying for the New Entry Price Adjustment.  The Office of the \nInterconnection shall not clear such contingent Sell Offer if it does not qualify for the New Entry \nPrice Adjustment. \n \n2. \nAll or any part of a Sell Offer from the Planned Generation Capacity \nResource submitted in accordance with section 5.14(c)(1) is the marginal Sell Offer that sets the \nCapacity Resource Clearing Price for the LDA. \n \n3. \nAcceptance of all or any part of a Sell Offer that meets the conditions in \nsection 5.14(c)(1)-(2) in the BRA increases the total Unforced Capacity committed in the BRA \n(including any minimum block quantity) for the LDA in which such Resource will be located \nfrom a megawatt quantity below the LDA Reliability Requirement to a megawatt quantity at or \nabove a megawatt quantity at the price-quantity point on the VRR Curve at which the price is \n0.40 times the applicable Net CONE divided by (one minus the pool-wide average EFORd) \nthrough the 2024/2025 Delivery Year, and beginning with the 2025/2026 Delivery Year, divided \nby the applicable ELCC Class Rating for the Reference Resource. \n \n4. \nSuch Capacity Market Seller submits Sell Offers in the BRA for the two \nimmediately succeeding Delivery Years for the entire Unforced Capacity of such Generation \nCapacity Resource committed in the first BRA under section 5.14(c)(1)-(2) equal to the lesser of: \nA) the price in such seller’s Sell Offer for the BRA in which such resource qualified as a Planned \nGeneration Capacity Resource that satisfies the conditions in section 5.14(c)(1)-(3); or B) 0.90 \ntimes the Net CONE applicable in the first BRA in which such Planned Generation Capacity \nResource meeting the conditions in section 5.14(c)(1)-(3) cleared, on an Unforced Capacity \nbasis, for such LDA. \n \n5. \nIf the Sell Offer is submitted consistent with section 5.14(c)(1)-(4) the \nforegoing conditions, then: \n \n(i) \nin the first Delivery Year, the Resource sets the Capacity Resource \nClearing Price for the LDA and all cleared resources in the LDA receive \nthe Capacity Resource Clearing Price set by the Sell Offer as the marginal \noffer, in accordance with Tariff, Attachment DD, section 5.12(a) and \nsection 5.14(a) above.  \n \n(ii) \nin either of the subsequent two BRAs, if any part of the Sell Offer from \nthe Resource clears, it shall receive the Capacity Resource Clearing Price"},{"page":73,"startToken":25068,"endToken":25540,"text":"for such LDA for its cleared capacity and for any additional minimum \nblock quantity pursuant to section 5.14(b) above; or \n \n(iii) \nif the Resource does not clear, it shall be deemed resubmitted at the \nhighest price per MW-day at which the megawatt quantity of Unforced \nCapacity of such Resource that cleared the first-year BRA will clear the \nsubsequent-year BRA pursuant to the optimization algorithm described in \nTariff, Attachment DD, section 5.12(a), and  \n \n(iv) \nthe resource with its Sell Offer submitted shall clear and shall be \ncommitted to the PJM Region in the amount cleared, plus any additional \nminimum-block quantity from its Sell Offer for such Delivery Year, but \nsuch additional amount shall be no greater than the portion of a minimum-\nblock quantity, if any, from its first-year Sell Offer satisfying section \n5.14(c)(1)-(3) above that is entitled to compensation pursuant to section \n5.14(b) above; and \n \n(v) \nthe Capacity Resource Clearing Price, and the resources cleared, shall be \nre-determined to reflect the resubmitted Sell Offer.  In such case, the \nResource for which the Sell Offer is submitted pursuant to section \n5.14(c)(1)-(4) above shall be paid for the entire committed quantity at the \nSell Offer price that it initially submitted in such subsequent BRA.  The \ndifference between such Sell Offer price and the Capacity Resource \nClearing Price (as well as any difference between the cleared quantity and \nthe committed quantity), will be treated as a Resource Make-Whole \nPayment in accordance with section 5.14(b) above.  Other capacity \nresources that clear the BRA in such LDA receive the Capacity Resource \nClearing Price as determined in section 5.14(a) above. \n \n6. \nThe failure to submit a Sell Offer consistent with section 5.14(c)(i)-(iii) \nabove in the BRA for Delivery Year 3 shall not retroactively revoke the New Entry Price \nAdjustment for Delivery Year 2.  However, the failure to submit a Sell Offer consistent with \nsection 5.14(c)(4) above in the BRA for Delivery Year 2 shall make the resource ineligible for \nthe New Entry Pricing Adjustment for Delivery Years 2 and 3. \n \n7. \nFor each Delivery Year that the foregoing conditions are satisfied, the \nOffice of the Interconnection shall maintain and employ in the auction clearing for such LDA a \nseparate VRR Curve, notwithstanding the outcome of the test referenced in Tariff, Attachment \nDD, section 5.10(a)(ii). \n \n8. \nOn or before August 1, 2012, PJM shall file with FERC under FPA \nsection 205, as determined necessary by PJM following a stakeholder process, tariff changes to \nestablish a long-term auction process as a not unduly discriminatory means to provide adequate \nlong-term revenue assurances to support new entry, as a supplement to or replacement of this \nNew Entry Price Adjustment.    \n \n \nd) \nQualifying Transmission Upgrade Payments"},{"page":74,"startToken":25540,"endToken":26073,"text":"A Capacity Market Seller that submitted a Sell Offer based on a Qualifying Transmission \nUpgrade that clears in the Base Residual Auction shall receive a payment equal to the Capacity \nResource Clearing Price, including any Locational Price Adder, of the LDA into which the \nQualifying Transmission Upgrade is to increase Capacity Emergency Transfer Limit, less the \nCapacity Resource Clearing Price, including any Locational Price Adder, of the LDA from \nwhich the upgrade was to provide such increased CETL, multiplied by the megawatt quantity of \nincreased CETL cleared from such Sell Offer.  Such payments shall be reflected in the \nLocational Price Adder determined as part of the Final Zonal Capacity Price for the Zone \nassociated with such LDAs, and shall be funded through a reduction in the Capacity Transfer \nRights allocated to Load-Serving Entities under Tariff, Attachment DD, section 5.15, as set forth \nin that section.  PJMSettlement shall be the Counterparty to any cleared capacity transaction \nresulting from a Sell Offer based on a Qualifying Transmission Upgrade.   \n \n \ne) \nLocational Reliability Charge  \n \nIn accordance with the Reliability Assurance Agreement, each LSE shall incur a Locational \nReliability Charge (subject to certain offsets and other adjustments as described in and Tariff, \nAttachment DD, section 5.15) equal to such LSE’s Daily Unforced Capacity Obligation in a \nZone during such Delivery Year multiplied by the applicable Final Zonal Capacity Price in such \nZone.  PJMSettlement shall be the Counterparty to the LSEs’ obligations to pay, and payments \nof, Locational Reliability Charges. \n \n \nf) \nThe Office of the Interconnection shall determine Zonal Capacity Prices in \naccordance with the following, based on the optimization algorithm: \n \ni) \nThe Office of the Interconnection shall calculate and post the Preliminary \nZonal Capacity Prices for each Delivery Year following the Base Residual Auction for such \nDelivery Year. The Preliminary Zonal Capacity Price for each Zone shall be the sum of: (1) the \nmarginal value of system capacity for the PJM Region, without considering locational \nconstraints; (2) the Locational Price Adder, if any, for the LDA in which such Zone is located; \nprovided however, that if the Zone contains multiple LDAs with different Capacity Resource \nClearing Prices, the Zonal Capacity Price shall be a weighted average of the Capacity Resource \nClearing Prices for such LDAs, weighted by the Unforced Capacity of Capacity Resources \ncleared in each such LDA; (3) an adjustment, if required, to account for adders paid to Annual \nResources in the LDA for which the zone is located; (4) an adjustment, if required, to account for \nResource Make-Whole Payments; and (5) an adjustment, if required to provide sufficient \nrevenue for payment of any PRD Credits, all as determined in accordance with the optimization \nalgorithm. \n \nii) \nThe Office of the Interconnection shall calculate and post the Adjusted \nZonal Capacity Price following each Incremental Auction.  The Adjusted Zonal Capacity Price \nfor each Zone shall equal the sum of:  (1) the average marginal value of system capacity \nweighted by the Unforced Capacity cleared in all auctions previously conducted for such \nDelivery Year (excluding any Unforced Capacity cleared as replacement capacity); (2) the \naverage Locational Price Adder weighted by the Unforced Capacity cleared in all auctions \npreviously conducted for such Delivery Year (excluding any Unforced Capacity cleared as"},{"page":75,"startToken":26073,"endToken":26519,"text":"replacement capacity); (3) an adjustment, if required, to account for adders paid to Annual \nResources for all auctions previously conducted for such Delivery Year (excluding any Unforced \nCapacity cleared as replacement capacity); (4) an adjustment, if required, to account for \nResource Make-Whole Payments for all actions previously conducted (excluding any Resource \nMake-Whole Payments to be charged to the buyers of replacement capacity); and (5) an \nadjustment, if required to provide sufficient revenue for payment of any PRD Credits; and (6) an \nadjustment, if required, to reflect any changes in final Accredited UCAP for resources that are \ncounted as capacity in accordance with Tariff, Attachment DD, section 5.3(b). The Adjusted \nZonal Capacity Price may decrease if Unforced Capacity is decommitted or the Resource \nClearing Price decreases in an Incremental Auction.  \n \niii) \nThe Office of the Interconnection shall calculate and post the Final Zonal \nCapacity Price for each Delivery Year after the final auction is held for such Delivery Year, as \nset forth above.  The Final Zonal Capacity Price for each Zone shall equal the Adjusted Zonal \nCapacity Price, as further adjusted to reflect any decreases in the Nominated Demand Resource \nValue of any existing Demand Resource cleared in the Base Residual Auction, First Incremental, \nor Second Incremental Auction. \n \n \ng) \nResource Substitution Charge \n \nEach Capacity Market Buyer in an Incremental Auction securing replacement \ncapacity shall pay a Resource Substitution Charge equal to the Capacity Resource Clearing Price \nresulting from such auction multiplied by the megawatt quantity of Unforced Capacity purchased \nby such Market Buyer in such auction.  \n \n \nh) \n[Reserved for future use] \n \nh-1) \n[Reserved for future use] \nh-2) \nMinimum Offer Price Rule Effective with the 2023/2024 Delivery Year \n \n(1) \nCertification Requirement.  \n \n(A) \nExcept for any RBP Resources committed through the Reliability \nBackstop Procurement, by no later than one hundred and fifty (150) days prior to the \ncommencement of the offer period of any RPM Auction conducted for the 2024/2025 Delivery \nYear and all subsequent Delivery Years, and by the date posted on the PJM website for the \n2023/2024 Delivery Year, each Capacity Market Seller must certify to the Office of \nInterconnection for each Generation Capacity Resource and each applicable DER Capacity \nAggregation Resource the Capacity Market Seller intends to offer into the RPM Auction, in \naccordance with the PJM Manuals:  \n \n(i) whether or not the Generation Capacity Resource is receiving or \nexpected to receive Conditioned State Support under any legislative or other governmental \npolicy or program that has been enacted or effective at the time of the certification; and   \n \n(ii) whether or not the Capacity Market Seller acknowledges and \nunderstands that the Exercise of Buyer-Side Market Power is not permitted in RPM Auctions,"},{"page":76,"startToken":26519,"endToken":27039,"text":"and does not intend to submit a Sell Offer for their Generation Capacity Resource as an Exercise \nof Buyer-Side Market Power. \n \n(B) \nAll Capacity Market Sellers shall be responsible for the accuracy \nof each certification and its conformance with the Tariff irrespective of any guidance developed \nby the Office of the Interconnection and the Market Monitoring Unit. \n \n(C) \nOnce a Capacity Market Seller has certified whether or not a \nGeneration Capacity Resource is receiving or expected to receive Conditioned State Support, the \ncertification requirements in subsection (A)(i) above do not apply and the status of such \nGeneration Capacity Resource will remain unchanged unless and until the Capacity Market \nSeller (or a subsequent Capacity Market Seller of the underlying resource) that owns or controls \nsuch Generation Capacity Resource provides a certification of a change in such status, the Office \nof the Interconnection removes such status, or by FERC order.  All Capacity Market Sellers shall \nhave an ongoing obligation to certify to the Office of Interconnection and the Market Monitoring \nUnit a Generation Capacity Resource’s material change in status regarding whether such \nresource is receiving or expected to receive Conditioned State Support within 30 days of such \nmaterial change. Nothing in this provision shall supersede the requirement for all Capacity \nMarket Sellers to certify to the Office of Interconnection pursuant to Tariff, Attachment DD, \nsection 5.14(h-2)(1)(A)(ii).  \n \n(2) \nDetermining Generation Capacity Resources Subject to the Minimum \nOffer Price Rule.   \n \n(A) \nConditioned State Support.   \n \n(i) If the Office of the Interconnection reasonably believes a \ngovernment policy or program would provide Conditioned State Support or a Capacity Market \nSeller certifies that it is receiving or is expected to receive Conditioned State Support associated \nwith a given Generation Capacity Resource, the Office of Interconnection shall submit, pursuant \nto section 205 of the Federal Power Act, 16 U.S.C. § 824d, a filing at FERC indicating the Office \nof the Interconnection’s intent to classify the government policy or program from which that \nsupport is derived as Conditioned State Support (and adding such policy or program to the list in \nTariff, Attachment DD-3) and apply the Minimum Offer Price Rule to each Generation Capacity \nResource reasonably expected to receive such Conditioned State Support.  If FERC has already \nruled on whether a specific government program or policy constitutes Conditioned State Support \nand such policy or program is listed in Tariff, Attachment DD-3, the Office of the \nInterconnection shall not be required to submit the filing described in the preceding sentence.   \n \n(ii) Government policies or programs that do not provide payments \nor other financial benefit outside of PJM markets and do not provide payment or other financial \nbenefit in exchange for the sale of a FERC-jurisdictional product conditioned on clearing in any \nRPM Auction do not constitute Conditioned State Support. Examples of such government \npolicies that do not constitute Conditioned State Support may include, but are not limited to: \npolicies designed to procure, incent, or require environmental attributes, whether bundled or \nunbundled (e.g., Renewable Energy Credits, Zero Emission Credits; Regional Greenhouse Gas \nInitiative); economic development programs and policies; tax incentives; state retail default"},{"page":77,"startToken":27039,"endToken":27637,"text":"service auctions; policies or programs that provide incentives related to fuel supplies; any \ncontract, legally enforceable obligation, or rate pursuant to the Public Utility Regulatory Policies \nAct or any other state-administered federal regulatory program (e.g., Cross-State Air Pollution \nRule). In addition, Conditioned State Support shall not be determined solely based on the \nbusiness model of the Capacity Market Seller, such that the fact that a Self-Supply Entity is the \nCapacity Market Seller, for example, is not a basis for determining Conditioned State Support.   \n \n(iii) Upon FERC acceptance (whether by order or operation of law) \nthat a government policy or program or contract with a state entity constitutes Conditioned State \nSupport, a Generation Capacity Resource for which a Capacity Market Seller certifies pursuant \nto Tariff, Attachment DD, section 5.14(h-2)(1)(A)(i) that it is receiving Conditioned State \nSupport or is reasonably expected to receive such Conditioned State Support, as identified by the \nOffice of the Interconnection, with the advice and input of the Market Monitoring Unit, will be \nsubject to the provisions of the Minimum Offer Price Rule. \n \n(B) \nExercise of Buyer-Side Market Power  \n \n(i) Except for a committed RBP Resource, if a Capacity Market \nSeller does not certify that it acknowledges the prohibition of the Exercise of Buyer Side Market \nPower and the Capacity Market Seller intends to exercise Buyer-Side Market Power for this \nGeneration Capacity Resource, then the underlying Capacity Resource shall be subject to the \nMOPR pursuant to Tariff, Attachment DD, section 5.14(h-2)(1)(A)(i). If the Office of the \nInterconnection and/or the Market Monitoring Unit reasonably suspects that a certification \nsubmitted under Tariff, Attachment DD, section 5.14(h-2)(1)(A)(ii) contains fraudulent or \nmaterial misrepresentations such that the Capacity Market Seller’s Generation Capacity \nResource may be the subject of a Sell Offer that would be an Exercise of Buyer-Side Market \nPower or otherwise reasonably suspects that a Generation Capacity Resource may be the subject \nof a Sell Offer that would be an Exercise of Buyer-Side Market Power, the Office of the \nInterconnection and/or the Market Monitoring Unit shall initiate a fact-specific review into the \nfacts and circumstances regarding the Generation Capacity Resource and whether the Capacity \nMarket Seller has the ability and incentive to exercise Buyer-Side Market Power with respect to \nsuch Generation Capacity Resource.  During such fact-specific review, the Capacity Market \nSeller will have the opportunity to explain and justify why a Sell Offer for the Generation \nCapacity Resource would not be an Exercise of Buyer-Side Market Power.  The Office of the \nInterconnection and/or the Market Monitoring Unit shall notify the Capacity Market Seller of the \nbases for inquiry and initiation of review at least 135 days in advance of the RPM Auction \nconducted for the 2024/2025 Delivery Year and all subsequent Delivery Years, and by the date \nposted on the PJM website for the 2023/2024 Delivery Year.  \n \nIn initiating a review, the Office of the Interconnection and/or the \nMarket Monitoring Unit shall provide the affected Capacity Market Seller, in writing, the basis \nfor its inquiry, including, but not limited to, the Generation Capacity Resource(s), and the \npurported beneficiary of any price suppression.  The Office of the Interconnection and/or the \nMarket Monitoring Unit may request from the Capacity Market Seller additional information and \ndocumentation that is reasonably related to the basis for its inquiry, provided that, the Office of \nthe Interconnection and the Market Monitoring Unit shall confer with the Capacity Market Seller \nin advance of any such requests.  The Capacity Market Seller shall provide any additional"},{"page":78,"startToken":27637,"endToken":28254,"text":"supporting information and documentation requested by the Office of the Interconnection and/or \nthe Market Monitoring Unit, and any other information and documentation the Capacity Market \nSeller believes may justify the conduct or action in question as not representing an Exercise of \nBuyer-Side Market Power, within 15 days or other such timeline as agreed to in writing by the \nOffice of the Interconnection, Market Monitoring Unit and Capacity Market Seller.   \n \nThe fact-specific review will determine, as necessary, whether a \nCapacity Market Seller has the ability and incentive to submit a Sell Offer for the Generation \nCapacity Resource that could be an Exercise of Buyer-Side Market Power, as follows: \n \n(a) To determine whether a Capacity Market Seller may \nhave Buyer Side Market Power associated with the Generation Capacity Resource for the \napplicable RPM Auction, the Office of the Interconnection and/or the Market Monitoring Unit \nwill perform ex-ante testing to determine the extent to which a shift in the supply curve by a \nnumber of megawatts equal to the size of the Generation Capacity Resource would affect RPM \nAuction clearing prices, where such analysis would reflect expected supply and demand \nconditions in the region of the market clearing prices and quantities in recent RPM Auctions, \nwould reflect whether the relevant LDAs have been constrained in recent RPM Auctions, and \nwould reflect reasonably expected material changes in an LDA including the modeling of the \nLDA and expected changes in supply and demand for the applicable Delivery Year.  To the \nextent the foregoing analyses show that the Generation Capacity Resource would have a material \neffect on RPM Auction clearing prices, the Capacity Market Seller shall be deemed to have the \nability to exercise Buyer Side Market Power. \n \n(b) To determine whether the Capacity Market Seller’s \nsubmission of a Sell Offer at any given price level for such Generation Capacity Resource may \nconstitute an Exercise of Buyer-Side Market Power, the Office of the Interconnection and/or the \nMarket Monitoring Unit shall perform ex-ante testing to determine whether, given the ability to \nsuppress prices identified in the relevant LDAs and the PJM Region, such price suppression \nwould be economically beneficial to the Capacity Market Seller by comparing its expected cost \nwith its economic benefit, and where the expected cost shall reflect the excess economic costs of \nthe resource above expected market revenues, and the expected benefit shall reflect the expected \ncost savings to the expected net short position (based on estimated capacity obligations and \nowned and contracted capacity measured on a three-year average basis for the three years \nstarting with the first day of the Delivery Year associated with the RPM Auction in which the \nGeneration Capacity Resource is being offered) in the relevant LDAs and RTO multiplied by the \nprice change resulting from offering the resource uneconomically. In this analysis, the Office of \nInterconnection and/or the Market Monitoring Unit shall consider whether any capacity \nobligations in which the capacity costs based on RPM Auction clearing prices are directly passed \nthrough to load and consider whether the price of any contracted capacity passes through RPM \nAuction clearing prices. If the expected benefit outweighs the expected cost, the Capacity Market \nSeller shall be deemed to have the incentive to exercise Buyer Side Market Power. If a resource \noffer can be justified, economically or otherwise, without consideration of the benefit to the \nCapacity Market Seller of the suppressed prices, the Capacity Market Seller shall be deemed not \nto have the incentive to exercise Buyer Side Market Power with respect to that resource. Out-of-\nmarket compensation (such as from renewable energy credits and zero emission credits) that are \nnot tied to either Conditioned State Support or a bilateral contract that directs the submission of"},{"page":79,"startToken":28254,"endToken":28813,"text":"an offer to lower market clearing prices may be used to support the economics of the resource \nunder review. \n \n(ii) The following nonexhaustive list of circumstances would \npreclude an inquiry into or determination regarding an Exercise of Buyer-Side Market Power in \nthe course of a review initiated pursuant to subsection (i) above:  (a) the Generation Capacity \nResource is a merchant generation supply resources that is not contracted to an entity with a \nLoad Interest; (b)  the Generation Capacity Resource is acquired by or under the contractual \ncontrol of the Capacity Market Seller through a competitive and non-discriminatory procurement \nprocess open to new and existing resources; or (c) the Generation Capacity Resource is owned \nby or bilaterally contracted to a Self-Supply Seller and such resource is demonstrated as \nconsistent with or included in the Self-Supply Seller’s long-range resource plan (e.g., a long-\nrange hedging plan) that is approved or otherwise reviewed and accepted by the RERRA, \nprovided that any such plan approval or contracts do not direct the submission of an uneconomic \noffer to deliberately lower market clearing prices or for the Capacity Market Seller to otherwise \nperform an Exercise of Buyer-Side Market Power. In addition, to the extent a Generation \nCapacity Resource may receive compensation in support of characteristics aligned with well-\ndemonstrated customer preferences, such compensation shall not, in and of itself, be a basis for \nthe determination of Buyer-Side Market Power. \n \n(iii) Based on the foregoing tests and fact-specific review, \nincluding the facts and circumstances of the Generation Capacity Resource, the Office of the \nInterconnection, with the advice and input of the Market Monitoring Unit, shall determine \nwhether a Generation Capacity Resource may be the subject of a Sell Offer that would be an \nExercise of Buyer-Side Market Power.  If the Office of the Interconnection, with the advice and \ninput of the Market Monitoring Unit, determines that a Generation Capacity Resource may be \nthe subject of a Sell Offer that would be an Exercise of Buyer-Side Market Power or the \nCapacity Market Seller certifies that it intends to exercise Buyer-Side Market Power, then such \nresource will be subject to the provisions of the Minimum Offer Price Rule.  If the resource will \nbe subject to the provisions of the Minimum Offer Price Rule, the Office of the Interconnection \nshall include in the notice a written explanation for such determination. A Capacity Market \nSeller that is dissatisfied with the Office of the Interconnection’s determination of whether a \ngiven Generation Capacity Resource is subject to the Minimum Offer Price Rule  may seek any \nremedies available to it from FERC; provided, however, that the Office of the Interconnection \nwill proceed with administration of the Tariff and market rules based on its determination \nhereunder unless FERC by order directs otherwise. \n \n(C) \nFailure to timely submit a certification.  Any Generation Capacity \nResource for which a Capacity Market Seller has not timely submitted the certifications required \nunder Tariff, Attachment DD, section 5.14(h-2)(1) shall be subject to the provisions of the \nMinimum Offer Price Rule.  Notwithstanding the foregoing, if a Capacity Market Seller submits \na timely unit-specific exception pursuant to Tariff, Attachment DD, section 5.14(h-2)(4) for the \nrelevant Delivery Year, and PJM approves the unit-specific MOPR Floor Offer Price, then the \nCapacity Market Seller may use such floor price regardless of whether it timely submitted the \nforegoing certifications."},{"page":80,"startToken":28813,"endToken":29313,"text":"(3) \nMinimum Offer Price Rule.  Any Sell Offer for a Generation Capacity \nResource that is subject to the provisions of the Minimum Offer Price Rule pursuant to Tariff, \nAttachment DD, section 5.14(h-2)(2) shall have an offer price no lower than the applicable \nMOPR Floor Offer Price, unless the applicable MOPR Floor Offer Price is higher than the \napplicable Market Seller Offer Cap, in which circumstance the Capacity Market Seller, to \nparticipate in an RPM Auction, must request a unit-specific value determined in accordance with \nthe unit-specific MOPR Floor Offer Price process, and the unit-specific MOPR Floor Offer Price \nshall establish the offer level for such resource.   \n \n(A) \nNew Entry MOPR Floor Offer Price. For a Generation Capacity \nResource that is subject to the provisions of the Minimum Offer Price Rule pursuant to Tariff, \nAttachment DD, section 5.14(h-2)(2) and for which a Sell Offer based on that resource, or any \nuprate of such   Generation Capacity Resource participating in the generation interconnection \nprocess under Tariff, Part IV, Subpart A, that has not cleared an RPM Auction for any Delivery \nYear,  the applicable MOPR Floor Offer Price, based on the net cost of new entry for the \nresource type, shall be, at the election of the Capacity Market Seller, (i) the unit-specific value \ndetermined in accordance with the unit-specific MOPR Floor Offer Price process in Tariff, \nAttachment DD, section 5.14(h-2)(4) below or (ii) if applicable, the default New Entry MOPR \nFloor Offer Price for the applicable resource based on the gross cost of new entry values shown \nin the table below, as adjusted for Delivery Years subsequent to the 2022/2023 or 2026/2027 \nDelivery Year, as applicable, net of estimated net energy and ancillary service revenues for the \nresource type and Zone in which the resource is located.  \n \nResource Type \nThrough the 2025/2026 \nDelivery Years:  \nGross Cost of New Entry \n(2022/2023 $/ MW-day) \n(Nameplate) \nFor the 2026/2027 Delivery \nYear and Subsequent Delivery \nYears:  \nGross Cost of New Entry \n(2026/2027 $/ MW-day) \n(Nameplate) \nNuclear \n$2,000 \n$2,568 \nCoal \n$1,068 \n$1,480 \nCombined Cycle \n$320 \n$540 \nCombustion Turbine \n$294 \n$394 \nFixed Solar PV \n$271 \n$298 \nTracking Solar PV \n$290 \n$321 \nOnshore Wind \n$420 \n$438 \nOffshore Wind \n$1,155 \n$1,351 \nBattery Energy Storage \n$532 \n$502 \n \nThe gross cost of new entry values in the table above are expressed in dollars per MW-day in \nterms of nameplate megawatts.  For purposes of submitting a Sell Offer, the gross cost of new \nentry values must be converted to a net cost of new entry by subtracting the estimated net energy \nand ancillary service revenues, as determined below, from the gross cost of new entry.  However, \nthe resultant net cost of new entry of the battery energy storage resource type in the table above \nmust be multiplied by 2.5.  The net cost of new entry based on nameplate capacity is then \nconverted to Unforced Capacity (“UCAP”) MW-day.  For the 2023/2024 and 2024/2025"},{"page":81,"startToken":29313,"endToken":29939,"text":"Delivery Years, the net cost of new entry is adjusted using: for battery storage, wind, and solar \nresource types, the applicable ELCC Class Rating; or for all other generation resource types, the \napplicable class average EFORd.  For the 2025/2026 Delivery Year and subsequent Delivery \nYears, the net cost of new entry is adjusted by the applicable class average Accredited UCAP \nFactor. The resulting default New Entry MOPR Floor Offer price in UCAP/MW-day terms shall \nbe applied to each MW offered for the Capacity Resource regardless of the actual Sell Offer \nquantity and regardless of whether the Sell Offer is for a Seasonal Capacity Performance \nResource. \n  \nCommencing with the Base Residual Auction for the 2023/2024 Delivery Year, the Office of the \nInterconnection shall adjust the default gross costs of new entry in the table above and post the \npreliminary estimates of the adjusted applicable default New Entry MOPR Floor Offer Prices on \nits website, by no later than one hundred fifty (150) days prior to the commencement of the offer \nperiod for each Base Residual Auction.  To determine the adjusted applicable default New Entry \nMOPR Floor Offer Prices for all resource types, the Office of the Interconnection shall adjust the \ngross costs of new entry utilizing, for combustion turbine and combined cycle resource types, the \nsame Applicable BLS Composite Index applied for such Delivery Year to adjust the CONE \nvalue used to determine the Variable Resource Requirement Curve, in accordance with Tariff, \nAttachment DD, section 5.10(a)(iv), and for all other resource types, the “BLS Producer Price \nIndex Turbines and Turbine Generator Sets” component of the Applicable BLS Composite Index \nused to determine the Variable Resource Requirement Curve shall be replaced with the “BLS \nProducer Price Index Final Demand, Goods Less Food & Energy, Private Capital Equipment” \nwhen adjusting the gross costs of new entry.  The resultant value shall then be then adjusted \nfurther by a factor of 1.022 for nuclear, coal, combustion turbine, and combine cycle resource \ntypes or 1.01 for solar, wind, and storage resource types to reflect the annual decline in bonus \ndepreciation scheduled under federal corporate tax law.  Updated estimates of the net energy and \nancillary service revenues for each default resource type and applicable Zone, which shall \ninclude, but are not limited to, consideration of Fuel Costs, Maintenance Adders and Operating \nCosts, as applicable, pursuant to Operating Agreement, Schedule 2 shall then be subtracted from \nthe adjusted gross costs of new entry to determine the adjusted New Entry MOPR Floor Offer \nPrice.  The net energy and ancillary services revenue is equal to the average of the annual net \nrevenues of the three most recent calendar years preceding the Base Residual Auction, where \nsuch annual net revenues shall be determined in accordance with the following and the PJM \nManuals:   \n \n(i) for nuclear resource type, the net energy and ancillary services \nrevenue estimate shall be determined by the gross energy market revenue determined by the \nproduct of [average annual zonal day-ahead LMP, times 8,760 hours times the annual average \nequivalent availability factor of all PJM nuclear resources] minus the total annual cost to produce \nenergy determined by the product of [8,760 hours times the annual average equivalent \navailability factor of all PJM nuclear resources times $9.02/MWh for a single unit plant or \n$7.66/MWh for a multi-unit plant] where these hourly cost rates include fuel costs and variable \noperation and maintenance expenses, inclusive of Maintenance Adder costs, plus an ancillary \nservices revenue of $3,350/MW-year to be included through the 2025/2026 Delivery Year;  \n \n(ii) for coal resource type, the net energy and ancillary services \nrevenue estimate shall be determined by a simulated dispatch of a 650 MW coal unit (with heat"},{"page":82,"startToken":29939,"endToken":30523,"text":"rate of 8,638 BTU/kWh and variable operations and maintenance variable operation and \nmaintenance expenses, inclusive of Maintenance Adder costs, of $9.50/MWh) using applicable \ncoal prices, as set forth in the PJM Manuals, plus reactive services revenue of $3,350/MW-year \nto be included through the 2025/2026 Delivery Year. The unit is committed day-ahead in \nprofitable blocks of at least eight hours, and then committed in real-time for profitable hours if \nnot already committed day ahead;  \n \n(iii) for combustion turbine resource type, the net energy and \nancillary services revenue estimate shall be determined in a manner consistent with the \nmethodology described in Tariff, Attachment DD, section 5.10(a)(v)(B) for the Reference \nResource combustion turbine.   \n \n(iv) for combined cycle resource type, the net energy and ancillary \nservices revenue estimate shall be determined in the same manner as that prescribed for a \ncombustion turbine resource type, except that the heat rate assumed for the combined cycle \nresource shall be 6,553 BTU/kwh, the variable operations and maintenance expenses for such \nresource, inclusive of Maintenance Adder costs, shall be $2.11/MWh, the Peak-Hour Dispatch \nscenario for both the Day-Ahead and Real-Time Energy Markets shall be modified to dispatch \nthe CC resource continuously during the full peak-hour period, as described in Peak-Hour \nDispatch, for each such period that the resource is economic (using the test set forth in such \nsection), rather than only during the four-hour blocks within such period that such resource is \neconomic, and the ancillary services revenue shall be $3,350/MW-year to be included through \nthe 2025/2026 Delivery Year.  \n \n(v) for solar PV resource type, the net energy and ancillary services \nrevenue estimate shall be determined using a solar resource model that provides the average MW \noutput level, expressed as a percentage of nameplate rating, by hour of day (for each of the 24-\nhours of a day) and by calendar month (for each of the twelve months of a year). The annual net \nenergy market revenues are determined by multiplying the solar output level of each hour by the \nreal-time zonal LMP applicable to such hour with this product summed across all of the hours of \nan annual period, plus an ancillary services revenue of $3,350/MW-year to be included through \nthe 2025/2026 Delivery Year.  Two separate solar resource models are used, one model for a \nfixed panel resource and a second model for a tracking panel resource;  \n \n(vi) for onshore wind resource type, the net energy and ancillary \nservices revenue estimate shall be determined using a wind resource model that provides the \naverage MW output level, expressed as a percentage of nameplate rating, by hour of day (for \neach of the 24-hours of a day) and by calendar month (for each of the twelve months of a year). \nThe annual energy market revenues are determined by multiplying the wind output level of each \nhour by the real-time zonal LMP applicable to such hour with this product summed across all of \nthe hours of an annual period, plus an ancillary services revenue of $3,350/MW-year to be \nincluded through the 2025/2026 Delivery Year; \n \n(vii) for offshore wind resource type, the net energy and ancillary \nservices revenue estimate shall be the product of [the average annual zonal real-time LMP times \n8,760 hours times an assumed annual capacity factor of 45%], plus an ancillary services revenue \nof $3,350/MW-year to be included through the 2025/2026 Delivery Year; and"},{"page":83,"startToken":30523,"endToken":31133,"text":"(viii) for Capacity Storage Resource, the net energy and ancillary \nservices revenue estimate shall be estimated by a simulated dispatch against historical real-time \nzonal LMPs where the resource is assumed to be dispatched for the four hours of highest LMP of \na daily twenty-four hour period if the average LMP of these four hours exceeds 120% of the \naverage LMP of the four lowest LMP hours of the same twenty-four hour period.  The net energy \nmarket revenues will be determined by the product of [hourly output of 1 MW times the hourly \nLMP for each hour of assumed discharging] minus the product of [hourly consumption of 1.2 \nMW times the hourly LMP for each hour of assumed charging] with this net value summed \nacross all of the hours of an annual period, plus an ancillary services revenue of $3,350/MW-year \nto be included through the 2025/2026 Delivery Year.  An 83.3% efficiency of the battery energy \nstorage resource is reflected by assuming each 1.0 MW of discharge requires 1.2 MW of charge.   \n \nBeginning with the Delivery Year that commences June 1, 2022, and continuing no later than for \nevery fourth Delivery Year thereafter, the Office of the Interconnection shall review the default \ngross cost of new entry values.  Such review may include, without limitation, analyses of the \nfixed development, construction, operation, and maintenance costs for such resource types.  \nBased on the results of such review, PJM shall propose either to modify or retain the default \ngross cost of new entry values stated in the table above.  The Office of the Interconnection shall \npost publicly and solicit stakeholder comment regarding the proposal.  If, as a result of this \nprocess, changes to the default gross cost of new entry values are proposed, the Office of the \nInterconnection shall file such proposed modifications with the FERC by October 1, prior to the \nconduct of the Base Residual Auction for the first Delivery Year in which the new values would \nbe applied.   \n \nAny Generation Capacity Resource that is subject to the provisions of the Minimum Offer Price \nRule pursuant to Tariff, Attachment DD, section 5.14(h-2)(2) and that has not previously cleared \nan RPM Auction for that or any prior Delivery Year and for which there is no default MOPR \nFloor Offer Price provided in accordance with this section, including hybrid resources, must seek \na unit-specific value determined in accordance with the unit-specific MOPR Floor Offer Price \nprocess below to participate in an RPM Auction.  Failure to obtain a unit-specific MOPR Floor \nOffer Price will result in the Office of the Interconnection rejecting any Sell Offer based on such \nresource for the relevant RPM Auction. \n \n(B) \nCleared MOPR Floor Offer Prices.   \n \nFor a Generation Capacity Resource that is subject to the \nprovisions of the Minimum Offer Price Rule pursuant to Tariff, Attachment DD, section 5.14(h-\n2)(2) and for which a Sell Offer based on that resource has previously cleared an RPM Auction \nfor any Delivery Year, the applicable Cleared MOPR Floor Offer Price shall be, at the election of \nthe Capacity Market Seller, (a) based on the unit-specific MOPR Floor Offer Price, as \ndetermined in accordance with Tariff, Attachment DD, section 5.14(h-2)(4) below, or (b) if \navailable, the default Avoidable Cost Rate for the applicable resource type shown in the table \nbelow, as adjusted for Delivery Years subsequent for the 2022/2023 or 2026/2027 Delivery \nYear, as applicable, to reflect changes in avoidable costs, net of projected PJM market revenues \nequal to the resource’s historical net energy and ancillary service revenues consistent with Tariff, \nAttachment DD, section 6.8(d)."},{"page":84,"startToken":31133,"endToken":31556,"text":"Existing Resource \nType \nThrough the \n2025/2026 Delivery \nYears:  \nDefault Gross ACR \n(2022/2023)  \n($/MW-day) \n(Nameplate) \nFor the 2026/2027 \nDelivery Year and \nSubsequent Delivery \nYears:  \nDefault Gross ACR \n(2026/2027) ($/ MW-\nday) Nameplate \nNuclear - single \n$697 \n$591 \nNuclear - dual \n$445 \n$537 \nCoal \n$80 \n$94 \nCombined Cycle \n$56 \n$113 \nCombustion Turbine \n$50 \n$52 \nSteam Oil & Gas \nNA \n$64 \nSolar PV \n(fixed and tracking) \n$40 \n$70 \nWind Onshore \n$83 \n$147 \n \nThe default gross Avoidable Cost Rate values in the table above are expressed in dollars per \nMW-day in terms of nameplate megawatts.  Through the 2024/2025 Delivery Year, for purposes \nof submitting a Sell Offer, the default Avoidable Cost Rate values must be net of estimated net \nenergy and ancillary service revenues, and then the difference is ultimately converted to \nUnforced Capacity (“UCAP”) MW-day, where the UCAP MW-day value will be determined \nbased on the resource-specific Accredited UCAP value for solar and wind resource types (with \nappropriate time-weighting for any winter Capacity Interconnection Rights) or the resource-\nspecific EFORd for all other generation resource types.  Effective for the 2025/2026 Delivery \nYear and subsequent Delivery Years, for purposes of submitting a Sell Offer, the default \nAvoidable Cost Rate values must be net of estimated net energy and ancillary service revenues, \nand then the difference is ultimately converted to Unforced Capacity (“UCAP”) MW-day, based \non the resource’s Accredited UCAP Factor. The resulting default Cleared MOPR Floor Offer \nprice in UCAP/MW-day terms shall be applied to each MW offered for the Capacity Resource \nregardless of actual Sell Offer quantity and regardless of whether the Sell Offer is for a Seasonal \nCapacity Performance Resource. \n \nCommencing with the Base Residual Auction for the 2023/2024 Delivery Year, the Office of the \nInterconnection shall adjust the default Avoidable Cost Rates in the table above, and post the \nadjusted values on its website, by no later than one hundred fifty (150) days prior to the \ncommencement of the offer period for each Base Residual Auction.  To determine the adjusted \nAvoidable Cost Rates, the Office of the Interconnection shall utilize the 10-year average Handy-\nWhitman Index in order to adjust the Gross ACR values to account for expected inflation. \nUpdated estimates of the net energy and ancillary service revenues shall be determined on a \nresource-specific basis in accordance with Tariff, Attachment DD, section 6.8(d) and the PJM \nManuals.  \n \nBeginning with the Delivery Year that commences June 1, 2022, and continuing no later than for \nevery fourth Delivery Year thereafter, the Office of the Interconnection shall review the default"},{"page":85,"startToken":31556,"endToken":32207,"text":"Avoidable Cost Rates for Capacity Resource that is subject to the provisions of the Minimum \nOffer Price Rule pursuant to Tariff, Attachment DD, section 5.14(h-2)(2) that have cleared in an \nRPM Auction for any Delivery Year.  Such review may include, without limitation, analyses of \nthe avoidable costs of such resource types.  Based on the results of such review, PJM shall \npropose either to modify or retain the default Avoidable Cost Rate values stated in the table \nabove.  The Office of the Interconnection shall post publicly and solicit stakeholder comment \nregarding the proposal.  If, as a result of this process, changes to the default Avoidable Cost Rate \nvalues are proposed, the Office of the Interconnection shall file such proposed modifications \nwith the FERC by October 1, prior to the conduct of the Base Residual Auction for the first \nDelivery Year in which the new values would be applied.   \n \nAny Generation Capacity Resource that is subject to the provisions of the Minimum Offer Price \nRule pursuant to Tariff, Attachment DD, section 5.14(h-2)(2) and that has previously cleared an \nRPM Auction for any Delivery Year and for which there is no default MOPR Floor Offer Price \nprovided in accordance with this section, including hybrid resources, must seek a unit-specific \nvalue determined in accordance with the unit-specific MOPR Floor Offer Price process below to \nparticipate in an RPM Auction.  Failure to obtain a unit-specific MOPR Floor Offer Price will \nresult in the Office of the Interconnection rejecting any Sell Offer based on such resource.  \n \n(4) \nUnit-Specific Exception.  A Capacity Market Seller intending to submit a \nSell Offer in any RPM Auction for a Generation Capacity Resource that is subject to the \nprovisions of the Minimum Offer Price Rule below the applicable default MOPR Floor Offer \nPrice may, at its election, submit a request for a unit-specific exception for such Capacity \nResource.  A Capacity Market Seller intending to submit a Sell Offer in any RPM Auction for a \nGeneration Capacity Resource that is under a fact-specific review for Buyer-Side Market Power \npursuant to Tariff, Attachment DD, section 5.14(h-2)(2)(B)(ii), and where the offer is below the \napplicable default MOPR Floor Offer Price may, at its election, submit a request for a unit-\nspecific exception for such Generation Capacity Resource.  A Sell Offer below the default \nMOPR Floor Offer Price, but no lower than the unit-specific MOPR Floor Offer Price, shall be \npermitted if the Capacity Market Seller obtains approval from the Office of the Interconnection \nor the Commission, prior to the RPM Auction in which it seeks to submit the Sell Offer. The \nunit-specific MOPR Floor Offer Price determined under this provision shall be based on the unit-\nspecific Accredited UCAP value for battery energy storage resource types and for solar and wind \ngeneration resource types (appropriately time-weighted for any winter Capacity Interconnection \nRights) or on the unit-specific EFORd for all other generation resource types, and shall be \napplied to each MW offered by the resource regardless of actual Sell Offer quantity and \nregardless of whether the Sell Offer is for a Seasonal Capacity Performance Resource.  Such Sell \nOffer is permissible because it is consistent with the competitive, cost-based, fixed, net cost of \nthe resource.  All supporting data must be provided for all requests.  The following requirements \nshall apply to requests for such determinations: \n \n(A) \nThe Capacity Market Seller shall submit a written request with all \nof the required documentation as described below and in the PJM Manuals.  For such purpose, \nthe Capacity Market Seller shall submit the unit-specific exception request to the Office of the \nInterconnection and the Market Monitoring Unit no later than one hundred twenty (120) days \nprior to the commencement of the offer period for the RPM Auction in which it seeks to submit \nits Sell Offer.  For such purpose, the Office of the Interconnection shall post, by no later than one"},{"page":86,"startToken":32207,"endToken":32817,"text":"hundred fifty (150) days prior to the commencement of the offer period for the relevant RPM \nAuction, a preliminary estimate for the relevant Delivery Year of the default Minimum Floor \nOffer Prices, determined pursuant to Tariff, Attachment DD, sections 5.14(h-2)(3)(A) and (B).  If \nthe final applicable default Minimum Floor Offer Price subsequently established for the relevant \nDelivery Year is less than the Sell Offer, the Sell Offer shall be permitted and no exception shall \nbe required. \n \n(B) \nFor a unit-specific exception for a Generation Capacity Resource \nthat is subject to the provisions of the Minimum Offer Price Rule pursuant to Tariff, Attachment \nDD, section 5.14(h-2)(2) and that has never cleared an RPM Auction, the Capacity Market Seller \nmust include in its request for an exception under this subsection documentation to support the \nfixed development, construction, operation, and maintenance costs of the Capacity Resource, as \nwell as estimates of offsetting net revenues.   \n \nThe financial modeling assumptions for calculating Cost of New Entry for Generation Capacity \nResources shall be: (i) nominal levelization of gross costs, (ii) asset life of twenty years, (iii) no \nresidual value, (iv) all project costs included with no sunk costs excluded, (v) use first year \nrevenues (which may include revenues from the sale of renewable energy credits or any other \nrevenues outside of PJM markets that do not constitute Conditioned State Support ), and (vi) \nweighted average cost of capital based on the actual cost of capital for the entity proposing to \nbuild the Capacity Resource.  Notwithstanding the foregoing, a Capacity Market Seller that seeks \nto utilize an asset life other than twenty years (but no greater than 35 years) shall provide \nevidence to support the use of a different asset life, including but not limited to, the asset life \nterm for such resource as utilized in the Capacity Market Seller’s financial accounting (e.g., \nindependently audited financial statements), or project financing documents for the resource or \nevidence of actual costs or financing assumptions of recent comparable projects to the extent the \nseller has not executed project financing for the resource (e.g., independent project engineer \nopinion or manufacturer’s performance guarantee), or opinions of third-party experts regarding \nthe reasonableness of the financing assumptions used for the project itself or in comparable \nprojects.  Capacity Market Sellers may also rely on evidence presented in federal filings, such as \nits FERC Form No. 1 or an SEC Form 10-K, to demonstrate an asset life other than 20 years of \nsimilar asset projects. \n \nSupporting documentation for project costs may include, as applicable and available, a complete \nproject description; environmental permits; vendor quotes for plant or equipment; evidence of \nactual costs of recent comparable projects; bases for electric and gas interconnection costs and \nany cost contingencies; bases and support for property taxes, insurance, operations and \nmaintenance (“O&M”) contractor costs, and other fixed O&M and administrative or general \ncosts; financing documents for construction-period and permanent financing or evidence of \nrecent debt costs of the seller for comparable investments; and the bases and support for the \nclaimed capitalization ratio, rate of return, cost-recovery period, inflation rate, or other \nparameters used in financial modeling.  In addition to the certification, signed by an officer of the \nCapacity Market Seller, the request must include a certification that the claimed costs accurately \nreflect, in all material respects, the seller’s reasonably expected costs of new entry and that the \nrequest satisfies all standards for a unit-specific exception hereunder.  The request also shall \nidentify all revenue sources (exclusive of any Conditioned State Support or bilateral contracts \nthat direct submission of an offer to lower RPM Auction clearing prices) relied upon in the Sell"},{"page":87,"startToken":32817,"endToken":33413,"text":"Offer to offset the claimed fixed costs, including, without limitation, long-term power supply \ncontracts, tolling agreements, evidence of compensation outside the PJM market not tied to \nConditioned State Support or a bilateral contract that directs submission of an offer to lower \nRPM Auction clearing prices, or tariffs on file with state regulatory agencies, and shall \ndemonstrate that such offsetting revenues are consistent, over a reasonable time period identified \nby the Capacity Market Seller, with the standard prescribed above.  In making such \ndemonstration, the Capacity Market Seller may rely upon forecasts of competitive electricity \nprices in the PJM Region based on well-defined models that include fully documented estimates \nof future fuel prices, variable operation and maintenance expenses, which may include \nMaintenance Adders, energy demand, emissions allowance prices, and expected environmental \nor energy policies that affect the seller’s forecast of electricity prices in such region, employing \ninput data from sources readily available to the public.  Documentation for net revenues also may \ninclude, as available and applicable, plant performance and capability information, including \nheat rate, start-up times and costs, forced outage rates, planned outage schedules, maintenance \ncycle, fuel costs and other variable operations and maintenance expenses, and ancillary service \ncapabilities.  Any evaluation of net revenues should be consistent with Operating Agreement, \nSchedule 2, including, but not limited to, consideration of Fuel Costs, Maintenance Adders and \nOperating Costs, as applicable.   \n \n(C) \nFor a Unit-Specific Exception for a Generation Capacity Resource \nthat is subject to the provisions of the Minimum Offer Price Rule pursuant to Tariff, Attachment \nDD, section 5.14(h-2)(2) and that has previously cleared an RPM Auction, the Capacity Market \nSeller shall submit a Sell Offer consistent with the unit-specific Market Seller Offer Cap process \npursuant to Tariff, Attachment DD, section 6.8; except that the 10% uncertainty adder may not \nbe included in the “Adjustment Factor.”  In addition and notwithstanding the requirements of \nTariff, Attachment DD, section 6.8, the Capacity Market Seller may, at its election, include in its \nrequest for an exception under this subsection documentation to support projected energy and \nancillary services markets revenues.  Such a request shall identify all revenue sources (exclusive \nof any Conditioned State Support or bilateral contracts that direct submission of an offer to lower \nRPM Auction clearing prices) relied upon in the Sell Offer to offset the claimed fixed costs, \nincluding, without limitation, long-term power supply contracts, tolling agreements, evidence of \ncompensation outside of PJM markets not tied to Conditioned State Support or a bilateral \ncontract that directs submission of an offer to lower RPM Auction clearing prices, or tariffs on \nfile with state regulatory agencies, and shall demonstrate that such offsetting revenues are \nconsistent, over a reasonable time period identified by the Capacity Market Seller, with the \nstandard prescribed above.  In making such demonstration, the Capacity Market Seller may rely \nupon forecasts of competitive electricity prices in the PJM Region based on well-defined models \nthat include fully documented estimates of future fuel prices, variable operation and maintenance \nexpenses, energy demand, which may include Maintenance Adders, and emissions allowance \nprices, and expected environmental or energy policies that affect the seller’s forecast of \nelectricity prices in such region, employing input data from sources readily available to the \npublic.  Documentation for net revenues also may include, as available and applicable, plant \nperformance and capability information, including heat rate, start-up times and costs, forced \noutage rates, planned outage schedules, maintenance cycle, fuel costs and other variable \noperations and maintenance expenses, and ancillary service capabilities.  Any evaluation of \nrevenues should include, but would not be not limited to, consideration of Fuel Costs,"},{"page":88,"startToken":33413,"endToken":33996,"text":"Maintenance Adders and Operating Costs, as applicable, pursuant to Operating Agreement, \nSchedule 2. \n \n \n(D) \nA Sell Offer evaluated at the unit-specific exception shall be \npermitted if the information provided reasonably demonstrates that the Sell Offer’s competitive, \nfixed, cost-based offer level is below the default MOPR Floor Offer Price, based on competitive \ncost advantages relative to the costs estimated by the default MOPR Floor Offer Price, including, \nwithout limitation, competitive cost advantages resulting from the Capacity Market Seller’s \nbusiness model, financial condition, tax status, access to capital or other similar conditions \naffecting the applicant’s costs, or based on net revenues that are reasonably demonstrated \nhereunder to be higher than those estimated by the default MOPR Floor Offer Price.  Capacity \nMarket Sellers shall demonstrate that claimed cost advantages or sources of net revenue that are \nirregular or anomalous, that do not reflect arm’s-length transactions, or that are not in the \nordinary course of the Capacity Market Seller’s business are consistent with the standards of this \nsubsection, and that out-of-market compensation is not tied to Conditioned State Support or a \nbilateral contract that directs submission of an offer to lower RPM Auction clearing prices.  \nFailure to adequately support such claimed cost advantages or revenues so as to enable the \nOffice of the Interconnection to make the determination required in this section will result in the \nelimination of consideration of the unsupported element(s) of a unit-specific exception by the \nOffice of the Interconnection. \n \n(E)  \nThe Capacity Market Seller must submit a sworn, notarized \ncertification of a duly authorized officer, certifying that the officer has personal knowledge of the \nunit-specific exception request and that to the best of his/her knowledge and belief: (1) the \ninformation supplied to the Market Monitoring Unit and the Office of Interconnection to support \nits request for an exception is true and correct; (2) the Capacity Market Seller has disclosed all \nmaterial facts relevant to the request for the exception; and (3) the request satisfies the criteria for \nthe exception.  \n \n(F) \nThe Market Monitoring Unit shall review, in an open and \ntransparent manner with the Capacity Market Seller and the Office of the Interconnection, the \ninformation and documentation in support of the request and shall provide its findings whether \nthe proposed Sell Offer is acceptable, in accordance with the standards and criteria hereunder, in \nwriting, to the Capacity Market Seller and the Office of the  Interconnection by no later than \nninety (90) days prior to the commencement of the offer period for such auction.  The Office of \nthe Interconnection shall also review, in an open and transparent manner, all exception requests \nand documentation and shall provide in writing to the Capacity Market Seller, and the Market \nMonitoring Unit, its determination whether the requested Sell Offer is acceptable and if not it \nshall calculate and provide to such Capacity Market Seller, a minimum Sell Offer based on the \ndata and documentation received, by no later than sixty-five (65) days prior to the \ncommencement of the offer period for the relevant RPM Auction.  After the Office of the \nInterconnection determines with the advice and input of Market Monitor, the acceptable \nminimum Sell Offer, the Capacity Market Seller shall notify the Market Monitoring Unit and the \nOffice of the Interconnection, in writing, of the minimum level of Sell Offer to which it agrees to \ncommit by no later than sixty (60) days prior to the commencement of the offer period for the \nrelevant RPM Auction, and in making such determination, the Capacity Market Seller may"},{"page":89,"startToken":33996,"endToken":34409,"text":"consider the applicable default MOPR Floor Offer Price and may select such default value if it is \nlower than the unit-specific determination.  A Capacity Market Seller that is dissatisfied with any \ndetermination hereunder may seek any remedies available to it from FERC; provided, however, \nthat the Office of the Interconnection will proceed with administration of the Tariff and market \nrules based on the lower of the applicable default MOPR Floor Offer Price and the unit-specific \ndetermination unless and until ordered to do otherwise by FERC.   \n \ni) \nCapacity Export Charges and Credits \n \n(1) \nCharge \n \nEach Capacity Export Transmission Customer shall incur for each day of each Delivery Year a \nCapacity Export Charge equal to the Reserved Capacity of Long-Term Firm Transmission \nService used for such export (“Export Reserved Capacity”) multiplied by (the Final Zonal \nCapacity Price for such Delivery Year for the Zone encompassing the interface with the Control \nArea to which such capacity is exported minus the Final Zonal Capacity Price for such Delivery \nYear for the Zone in which the resources designated for export are located, but not less than \nzero).  If more than one Zone forms the interface with such Control Area, then the amount of \nReserved Capacity described above shall be apportioned among such Zones for purposes of the \nabove calculation in proportion to the flows from such resource through each such Zone directly \nto such interface under CETO/CETL analysis conditions, as determined by the Office of the \nInterconnection using procedures set forth in the PJM Manuals.  The amount of the Reserved \nCapacity that is associated with a fully controllable facility that crosses such interface shall be \ncompletely apportioned to the Zone within which such facility terminates. \n \n(2) \nCredit \n \nTo recognize the value of firm Transmission Service held by any such Capacity Export \nTransmission Customer, such customer assessed a charge under section 5.14(i)(1) above also \nshall receive a credit, comparable to the Capacity Transfer Rights provided to Load-Serving \nEntities under Tariff, Attachment DD, section 5.15.  Such credit shall be equal to the locational \ncapacity price difference specified in section 5.14(i)(1) above times the Export Customer's \nAllocated Share determined as follows: \n \nExport Customer’s Allocated Share equals  \n \n(Export Path Import * Export Reserved Capacity) / \n \n(Export Reserved Capacity + Daily Unforced Capacity Obligations of all LSEs in such Zone). \n \nWhere: \n \n“Export Path Import” means the megawatts of Unforced Capacity imported into the export \ninterface Zone from the Zone in which the resource designated for export is located."},{"page":90,"startToken":34409,"endToken":34568,"text":"If more than one Zone forms the interface with such Control Area, then the amount of Export \nReserved Capacity shall be apportioned among such Zones for purposes of the above calculation \nin the same manner as set forth in subsection (i)(1) above.  \n \n(3) \nDistribution of Revenues \n \nAny revenues collected from the Capacity Export Charge with respect to any capacity export for \na Delivery Year, less the credit provided in subsection (i)(2) for such Delivery Year, shall be \ndistributed to the Load Serving Entities in the export-interface Zone that were assessed a  \n \nLocational Reliability Charge for such Delivery Year, pro rata based on the Daily Unforced \nCapacity Obligations of such Load-serving Entities in such Zone during such Delivery Year. If \nmore than one Zone forms the interface with such Control Area, then the revenues shall be \napportioned among such Zones for purposes of the above calculation in the same manner as set \nforth in subsection (i)(1) above."},{"page":91,"startToken":34568,"endToken":35197,"text":"6.6 \nOffer Requirement for Capacity Resources \n \n \n(a) \nTo avoid application of subsection (h) below, (1) all of the installed capacity of all \nExisting Generation Capacity Resources located in the PJM Region, and (2) all of the RBP \nUCAP MW that is committed in the Reliability Backstop Procurement through the term of the \ncommitment, shall be offered by the Capacity Market Seller that owns or controls all or part of \nsuch resource (which may include submission as Self-Supply) in all RPM Auctions for each \nDelivery Year, less any amount determined by the Office of the Interconnection to be eligible for \nan exception to this RPM must-offer requirement, where installed capacity is determined as of \nthe date on which bidding commences for each RPM Auction pursuant to Tariff, Attachment \nDD, section 5.6.6.  Beginning with the 2025/2026 Delivery Year and subsequent Delivery Years, \na Planned Generation Capacity Resource associated with a notice of intent to offer submitted \npursuant to Tariff, Attachment DD, section 5.5 shall be required to be offered by the Capacity \nMarket Seller of such resource in the relevant RPM Auction. Through the 2024/2025 Delivery \nYear, the Unforced Capacity of such resources is determined using the EFORd value that is \nsubmitted by the Capacity Market Seller in its Sell Offer, which shall not exceed the maximum \nEFORd for that resource as defined in section 6.6(b). Starting with the 2025/2026 Delivery Year, \nthe Unforced Capacity of such resource is determined using the effective Accredited UCAP \nFactor for that resource.  If a resource should be included on the list of Existing Generation \nCapacity Resources subject to the RPM must-offer requirement that is maintained by the Market \nMonitoring Unit pursuant to Tariff, Attachment M-Appendix, section II.C.1, but is omitted \ntherefrom whether by mistake of the Market Monitoring Unit or failure of the Capacity Market \nSeller that owns or controls all or part of such resource to provide information about the resource \nto the Market Monitoring Unit, this shall not excuse such resource from the RPM must-offer \nrequirement.  \n \n \n(b) \nThrough the 2024/2025 Delivery Year, for each Existing Generation Capacity \nResource, a potential Capacity Market Seller must timely provide to the Market Monitoring Unit \nand the Office of the Interconnection all data and documentation required under this section 6.6 \nto establish the maximum EFORd applicable to each resource in accordance with standards and \nprocedures specified in the PJM Manuals.  The maximum EFORd that may be used in a Sell \nOffer for RPM Auctions held prior to the date on which the final EFORds used for a Delivery \nYear are posted, is the greater of (i) the average EFORd for the five consecutive years ending on \nthe September 30 that last precedes the Base Residual Auction, or (ii) the EFORd for the 12 \nmonths ending on the September 30 that last precedes the Base Residual Auction. \n \nNotwithstanding the foregoing, a Capacity Market Seller may request an alternate maximum \nEFORd for Sell Offers submitted in such auctions if it has a documented, known reason that \nwould result in an increase in its EFORd, by submitting a written request to the Market \nMonitoring Unit and Office of the Interconnection, along with data and documentation required \nto support the request for an alternate maximum EFORd, by no later one hundred twenty (120) \ndays prior to the commencement of the offer period for the Base Residual Auction for the \napplicable Delivery Year.  The Capacity Market Seller must address any concerns identified by \nthe Market Monitoring Unit and/or the Office of the Interconnection regarding the data and \ndocumentation provided and attempt to reach agreement with the Market Monitoring Unit on the \nlevel of the alternate maximum EFORd by no later than ninety (90) days prior to the"},{"page":92,"startToken":35197,"endToken":35772,"text":"commencement of the offer period for the Base Residual Auction for the applicable Delivery \nYear.  As further described in Tariff, Attachment M-Appendix, section II.C, the Market \nMonitoring Unit shall notify the Capacity Market Seller and the Office of the Interconnection in \nwriting of its determination of the requested alternate maximum EFORd by no later than ninety \n(90) days prior to the commencement of the offer period for the Base Residual Auction for the \napplicable Delivery Year.  By no later than eighty (80) days prior to the commencement of the \noffer period for the Base Residual Auction for the applicable Delivery Year, the Capacity Market \nSeller shall notify the Office of the Interconnection and the Market Monitoring Unit in writing \nwhether it agrees with the Market Monitoring Unit on the alternate maximum EFORd or, if no \nagreement has been reached, specifying the level of alternate maximum EFORd to which it \ncommits.  If a Capacity Market Seller fails to request an alternate maximum EFORd prior to the \nspecified deadlines, the maximum EFORd for the applicable RPM Auction shall be deemed to be \nthe default EFORd calculated pursuant to this section. \n \nThe maximum EFORd that may be used in a Sell Offer for Third Incremental Auction, and for \nConditional Incremental Auctions held after the date on which the final EFORd used for a \nDelivery Year is posted, is the EFORd for the 12 months ending on the September 30 that last \nprecedes the submission of such offers. \n \n \n(c) \n[Reserved for Future Use] \n \n \n(d) \nThrough the 2024/2025 Delivery Year, in the event that a Capacity Market Seller \nand the Market Monitoring Unit cannot agree on the maximum level of the alternate EFORd that \nmay be used in a Sell Offer for RPM Auctions held prior to the date on which the final EFORds \nused for a Delivery Year are posted, the Office of the Interconnection shall make its own \ndetermination of the maximum level of the alternate EFORd based on the requirements of the \nTariff and the PJM Manuals, per Tariff, Attachment DD, section 5.8, by no later than sixty-five \n(65) days prior to the commencement of the offer period for the Base Residual for the applicable \nDelivery Year, and shall notify the Capacity Market Seller and the Market Monitoring Unit in \nwriting of such determination. \n \n \n(e) \nThrough the 2024/2025 Delivery Year, nothing in this section precludes the \nCapacity Market Seller from filing a petition with FERC seeking a determination of whether the \nEFORd complies with the requirements of the Tariff.   \n \n \n(f) \nThrough the 2024/2025 Delivery Year, notwithstanding the foregoing, a Capacity \nMarket Seller may submit an EFORd  that it chooses for an RPM Auction held prior to the date \non which the final EFORd used for a Delivery Year is posted, provided that (i) it has participated \nin good faith with the process described in this section 6.6 and in Tariff, Attachment M-\nAppendix, section II.C, (ii) the offer is no higher than the level defined in any agreement reached \nby the Capacity Market Seller and the Market Monitoring Unit that resulted from the foregoing \nprocess, and (iii) the offer is accepted by the Office of the Interconnection subject to the criteria \nset forth in the Tariff and the PJM Manuals.   \n \n \n(g) \nA Capacity Market Seller that owns or controls an existing generation resource in \nthe PJM Region that is capable of qualifying as an Existing Generation Capacity Resource as of"},{"page":93,"startToken":35772,"endToken":36287,"text":"the date on which bidding commences for an RPM Auction may not avoid the rule in subsection \n(a) or be removed from Capacity Resource status by failing to qualify as a Generation Capacity \nResource, or by attempting to remove a unit previously qualified as a Generation Capacity \nResource from classification as a Capacity Resource for that RPM Auction.  However, \ngeneration resource may qualify for an exception to the RPM must-offer requirement, as shown \nby appropriate documentation, if the Capacity Market Seller that owns or controls such resource \ndemonstrates that it: (i) is reasonably expected to be physically unable to participate in the \nrelevant Delivery Year; (ii) has a financially and physically firm commitment to an external sale \nof its capacity, or (iii) was interconnected to the Transmission System as an Energy Resource \nand not subsequently converted to a Capacity Resource.   \n \nHowever, in any Delivery Year in which a Capacity Resource has committed RBP UCAP MW, \nthrough the Reliability Backstop Procurement such Capacity Resource shall not be eligible for an \nexception to the RPM must-offer requirement, under Tariff, Attachment DD, section 6.6A, based \non having a financially and physically firm commitment to an external sale of its capacity. \n \nNotwithstanding the foregoing, nothing herein provides a defense to a claim of withholding, \nmarket manipulation, or the exercise of market power by any entity who is affiliated with or are \nunder common ownership or control of a Capacity Market Seller that does not submit an offer \nfor a Generation Capacity Resource that obtains an exception to the capacity must-offer \nrequirement. \n \n \nIn order to establish that a resource is reasonably expected to be physically unable to \nparticipate in the relevant auction as set forth in (i) above, the Capacity Market Seller must \ndemonstrate that: \n \nA. It has a documented plan in place to retire the resource prior to or during the Delivery \nYear, and has submitted a notice of Deactivation to the Office of the Interconnection \nconsistent with Tariff, Part V, section 113.1, without regard to whether the Office of the \nInterconnection has requested the Capacity Market Seller to continue to operate the \nresource beyond its desired deactivation date in accordance with Tariff, Part V, section \n113.2 for the purpose of maintaining the reliability of the PJM Transmission System and \nthe Capacity Market Seller has agreed to do so; \n \nB. Significant physical operational restrictions cause long term or permanent changes to the \ninstalled capacity value of the resource, or the resource is under major repair that will \nextend into the applicable Delivery Year, that will result in the imposition of RPM \nperformance penalties pursuant to Tariff, Attachment DD; \n \nC. The Capacity Market Seller is involved in an ongoing regulatory proceeding (e.g. – \nregarding potential environmental restrictions) specific to the resource and has received \nan order, decision, final rule, opinion or other final directive from the regulatory authority \nthat will result in the retirement of the resource; or \n \nD. A resource considered an Existing Generating Capacity Resource because it cleared an \nRPM Auction for a Delivery Year prior to the Delivery Year of the relevant auction, but"},{"page":94,"startToken":36287,"endToken":36897,"text":"which is not yet in service, is unable to achieve full commercial operation prior to the \nDelivery Year of the relevant auction.  The Capacity Market Seller must submit to the \nOffice of the Interconnection and the Market Monitoring Unit a written sworn, notarized \nstatement of a corporate officer certifying that the resource will not be in full commercial \noperation prior to the referenced Delivery Year. \nIn order to establish that a resource has a financially and physically firm commitment to \nan external sale of its capacity as set forth in (ii) above, the Capacity Market Seller must \ndemonstrate that it has entered into a unit-specific bilateral transaction for service to load located \noutside the PJM Region, by a demonstration that such resource is identified on a unit-specific \nbasis as a network resource under the transmission tariff for the control area applicable to such \nexternal load, or by an equivalent demonstration of a financially and physically firm commitment \nto an external sale.  The Capacity Market Seller additionally shall identify the megawatt amount, \nexport zone, and time period (in days) of the export. \nA Capacity Market Seller that seeks approval for an exception to the RPM must-offer \nrequirement, for any reason other than the reason specified in Paragraph A above, shall first \nsubmit such request in writing, along with all supporting data and documentation, to the Market \nMonitoring Unit for evaluation, notifying the Office of the Interconnection by copy of the same, \nby no later than one hundred twenty (120) days prior to the commencement of the offer period \nfor the applicable RPM Auction.   \n \nIn order to obtain an exception to the RPM must-offer requirement for the reason \nspecified in Paragraph A above, a Capacity Market Seller shall first submit a preliminary \nexception request in writing, along with supporting data and documentation indicating the \nreasons and conditions upon which the Capacity Market Seller is relying in its analysis of \nwhether to retire such resource, to the Market Monitoring Unit for evaluation, notifying the \nOffice of the Interconnection by copy of the same, by no later than (a) the September 1 that last \nprecedes the Base Residual Auction and (b) two hundred forty (240) days prior to the \ncommencement of the offer period for the applicable Incremental Auction.  By no later than five \n(5) Business Days after the notification deadline for any such preliminary exception requests, the \nOffice of the Interconnection will post on its website a summary of the number of megawatts of \nGeneration Capacity Resources for which it has received notification of preliminary exception \nrequests, on an aggregate basis by Zone and Locational Deliverability Area that comprises a \nsubset of a Zone, as specified in the PJM Manuals. \n \nThereafter, as applicable, such Capacity Market Seller shall by no later than (a) the \nDecember 1 that last precedes the Base Residual Auction for the applicable Delivery Year, or (b) \none hundred twenty (120) days prior to the commencement of the offer period for the applicable \nIncremental Auction, either (a) notify the Office of the Interconnection and the Market \nMonitoring Unit in writing that it is withdrawing its preliminary exception request and \nexplaining the changes to its analysis of whether to retire such resource that support its decision \nto withdraw, or (b) demonstrate that it has met the requirements specified under Paragraph A \nabove.  By no later than five (5) Business Days after the notification deadline for such \nnotification, the Office of the Interconnection will post on its website a revised summary of the \nnumber of megawatts of Generation Capacity Resources for which it has received requests for \nexceptions to the RPM must-offer requirement for the reason specified in Paragraph A above, on"},{"page":95,"startToken":36897,"endToken":37504,"text":"an aggregate basis by Zone and Locational Deliverability Area that comprises a subset of a Zone, \nas specified in the PJM Manuals. \nA Capacity Market Seller that seeks to remove a Generation Capacity Resource from \nCapacity Resource status shall first submit a preliminary request in writing, along with \nsupporting data and documentation indicating the reasons and conditions upon which the \nCapacity Market Seller is relying in its analysis of whether to remove the Capacity Resource \nstatus of such resource to the Market Monitoring Unit for evaluation, notifying the Office of the \nInterconnection by copy of the same, by no later than (a) the September 1 that last precedes the \nBase Residual Auction, and (b) two hundred forty (240) days prior to the commencement of the \noffer period for the applicable Incremental Auction.  By no later than five (5) Business Days \nafter the notification deadline for any such preliminary requests, the Office of the \nInterconnection will post on its website a summary of the number of megawatts of Generation \nCapacity Resources for which it has received notification of preliminary requests, on an \naggregate basis by Zone and Locational Deliverability Area that comprises a subset of a Zone, as \nspecified in the PJM Manuals. \n \nThereafter, as applicable, such Capacity Market Seller shall, by no later than (a) the \nDecember 1 that last precedes the Base Residual Auction for the applicable Delivery Year, or (b) \none hundred twenty (120) days prior to the commencement of the offer period for the applicable \nIncremental Auction, notify the Office of the Interconnection and the Market Monitoring Unit in \nwriting that it is either (a) withdrawing its preliminary request and explaining the changes to its \nanalysis that support its decision to withdraw, or (b) confirming its preliminary decision to \nremove the Generation Capacity Resource from Capacity Resource status.  By no later than five \n(5) Business Days after the notification deadline for such notification, the Office of the \nInterconnection will post on its website a revised summary of the number of megawatts of \nGeneration Capacity Resources for which it has received requests to remove its Capacity \nResource status, on an aggregate basis by Zone and Locational Deliverability Area that \ncomprises a subset of a Zone, as specified in the PJM Manuals. \nThe Market Monitoring Unit shall analyze the effects of the proposed removal of a \nGeneration Capacity Resource from Capacity Resource status with regard to potential market \npower issues and shall notify the Capacity Market Seller and the Office of the Interconnection in \nwriting of its determination of the request to remove the Generation Capacity Resource from \nCapacity Resource status, and whether a market power issue has been identified, by no later than \nninety (90) days prior to the commencement of the offer period for the applicable RPM Auction. \nSuch notice shall include the specific market power impact resulting from the proposed removal \nof the Generation Capacity Resource from Capacity Resource status, as well as an initial \nassessment of any steps that could be taken to mitigate the market power impact. \nA Capacity Market Seller may only remove the Generation Capacity Resource from \nCapacity Resource status if (i) the Market Monitoring Unit has determined that the Generation \nCapacity Resource meets the applicable criteria set forth in Tariff, Attachment DD, sections \n5.6.6 and this section 6.6 and the Office of the Interconnection agrees with this determination, or \n(ii) the Commission has issued an order terminating the Capacity Resource status of the resource, \nor (iii) it is required as set forth in Tariff, Attachment DD, section 6.6A(c).  Any RBP Resource \ncommitted through the Reliability Backstop Procurement shall not be allowed to remove"},{"page":96,"startToken":37504,"endToken":38137,"text":"Capacity Resource status for the portion of the resource with committed RBP UCAP MW \nthrough the term of such commitment.  Nothing herein shall require a Market Seller to offer its \nresource into an RPM Auction prior to seeking to remove a resource from Capacity Resource \nstatus, subject to satisfaction of this section 6.6.  A Generation Capacity Resource that is \nremoved from Capacity Resource status shall no longer qualify as an Existing Generation \nCapacity Resource, and the Capacity Interconnection Rights associated with such facility shall \nbe subject to termination in accordance with the rules described in Tariff, Part VI, section \n230.3.3. The Office of the Interconnection shall amend the applicable Interconnection Service \nAgreement or wholesale market participation agreement to reflect any such removal of the \nCapacity Interconnection Rights, and shall report the amended agreement to the Commission in \nthe same manner as the original (e.g., FERC filing or Electronic Quarterly Reports). The Office \nof the Interconnection shall file the amended agreement unexecuted if the Interconnection \nCustomer or wholesale market participant does not sign the amended Interconnection Service \nAgreement or wholesale market participation agreement. \nIf the Capacity Market Seller disagrees with the Market Monitoring Unit’s determination \nof its request to remove a resource from Capacity Resource status or its request for an exception \nto the RPM must-offer requirement, it must notify the Market Monitoring Unit in writing, with a \ncopy to the Office of the Interconnection, of the same by no later than eighty (80) days prior to \nthe commencement of the offer period for the applicable RPM Auction.  After the Market \nMonitoring Unit has made its determination of whether a resource may be removed from \nCapacity Resource status, or whether the resource meets one of the exceptions thereto, and has \nnotified the Capacity Market Seller and the Office of the Interconnection of the same pursuant to \nTariff, Attachment M-Appendix, section II.C.4, the Office of the Interconnection shall approve \nor deny the request.  The request shall be deemed to be approved by the Office of the \nInterconnection, consistent with the determination of the Market Monitoring Unit, unless the \nOffice of the Interconnection notifies the Capacity Market Seller and Market Monitoring Unit, \nby no later than sixty-five (65) days prior to the date on which the offer period for the applicable \nRPM Auction commences, that the request is denied. \nIf the Market Monitoring Unit does not timely notify the Capacity Market Seller and the \nOffice of the Interconnection of its determination of the request to remove a Generation Capacity \nResource from Capacity Resource status or for an exception to the RPM must-offer requirement, \nthe Office of the Interconnection shall make the determination whether the request shall be \napproved or denied, and will notify the Capacity Market Seller of its determination in writing, \nwith a copy to the Market Monitoring Unit, by no later than sixty-five (65) days prior to the date \non which the offer period for the applicable RPM Auction commences. \nAfter the Market Monitoring Unit and the Office of the Interconnection have made their \ndeterminations of whether a resource meets the criteria to qualify for an exception to the RPM \nmust-offer requirement, the Capacity Market Seller must notify the Market Monitoring Unit and \nthe Office of the Interconnection whether it intends to exclude from its Sell Offer some or all of \nthe subject capacity on the basis of an identified exception by no later than sixty-five (65) days \nprior to the date on which the offer period for the applicable RPM Auction commences.  PJM \ndoes not make determinations of whether withholding of capacity constitutes market power.  A \nGeneration Capacity Resource that does not qualify for submission into an RPM Auction \nbecause it is not owned or controlled by the Capacity Market Seller for a full Delivery Year is"},{"page":97,"startToken":38137,"endToken":38738,"text":"not subject to the offer requirement hereunder; provided, however, that a Capacity Market Seller \nplanning to transfer ownership or control of a Generation Capacity Resource during a Delivery \nYear pursuant to a sale or transfer agreement entered into after March 26, 2009 shall be required \nto satisfy the offer requirement hereunder for the entirety of such Delivery Year and may satisfy \nsuch requirement by providing for the assumption of this requirement by the transferee of \nownership or control under such agreement.  \n \nIf a Capacity Market Seller doesn’t timely seek to remove a Generation Capacity \nResource from Capacity Resource status or timely submit a request for an exception to the RPM \nmust-offer requirement, the Generation Capacity Resource shall only be removed from Capacity \nResource status, and may only be approved for an exception to the RPM must-offer requirement, \nupon the Capacity Market Seller requesting and receiving an order from FERC, prior to the close \nof the offer period for the applicable RPM Auction, directing the Office of the Interconnection to \nremove the resource from Capacity Resource status and/or granting an exception to the RPM \nmust-offer requirement or a waiver of the RPM must-offer requirement as to such resource.   \n \n \n(h) \nAny existing generation resource located in the PJM Region that satisfies the \ncriteria in the definition of Existing Generation Capacity Resource as of the date on which \nbidding commences for the Base Residual Auction for a Delivery Year, that is not offered into \nsuch Base Residual Auction, and that does not meet any of the exceptions stated in the prior \nsubsection (g): (i) may not participate in any subsequent Incremental Auctions conducted for \nsuch Delivery Year; (ii) shall not receive any payments under Tariff, Attachment DD, section \n5.14 for such Delivery Year for the capacity of such Generation Capacity Resources; and (iii) \nshall not be permitted to satisfy any LSE’s Unforced Capacity Obligation, or any entity’s \nobligation to obtain the commitment of Capacity Resources, for such Delivery Year.   \n \n \nAll generation resources located in the PJM Region that satisfy the criteria in the \ndefinition of Existing Generation Capacity Resource as of the date on which bidding commences \nfor an Incremental Auction for a particular Delivery Year, but that did not satisfy such criteria as \nof the date that on which bidding commenced in the Base Residual Auction for that Delivery \nYear, that is not offered into that Incremental Auction, and that does not meet any of the \nexceptions stated in the prior subsection (g): (i) may not participate in any subsequent \nIncremental Auctions conducted for such Delivery Year; (ii) shall not receive any payments \nunder Tariff, Attachment DD, section 5.14 for such Delivery Year for the capacity of such \nGeneration Capacity Resources; and (iii) shall not be permitted to satisfy any LSE’s Unforced \nCapacity Obligation, or any entity’s obligation to obtain the commitment of Capacity Resources, \nfor such Delivery Year. \n \n \nAny Planned Generation Capacity Resource associated with a notice of intent to offer \ninto a particular RPM Auction that is not offered into the associated RPM Auction and all \nExisting Generation Capacity Resources that are offered into a Base Residual Auction or \nIncremental Auction for a particular Delivery Year but do not clear in such auction, that are not \noffered into each subsequent Incremental Auction, and that do not meet any of the exceptions \nstated in the prior subsection (g): (i) may not participate in any Incremental Auctions conducted \nfor such Delivery Year subsequent to such failure to offer; (ii) shall not receive any payments \nunder Tariff, Attachment DD, section 5.14 for such Delivery Year for the capacity of such"},{"page":98,"startToken":38738,"endToken":39155,"text":"Generation Capacity Resources; and (iii) shall not be permitted to satisfy any LSE’s Unforced \nCapacity Obligation, or any entity’s obligation to obtain the commitment of Capacity Resources, \nfor such Delivery Year. \n \n \nAny such Existing Generation Capacity Resources may also be subject to further action \nby the Market Monitoring Unit under the terms of Tariff, Attachment M and Tariff, Attachment \nM – Appendix. \n \n \n(i) \nIn addition to the remedies set forth in subsections (g) and (h) above, if the \nMarket Monitoring Unit determines that one or more Capacity Market Sellers’ failure to offer \npart or all of one or more existing generation resources, for which the Office of the \nInterconnection has not approved an exception to the RPM must-offer requirement, into an RPM \nAuction as required by this Section 6.6 would result in an increase of greater than five percent in \nany Zonal Capacity Price determined through such auction, and the Office of the Interconnection \nagrees with that determination, the Office of the Interconnection shall apply to FERC for an \norder, on an expedited basis, directing such Capacity Market Seller to participate in the relevant \nRPM Auction, or for other appropriate relief, and PJM will postpone clearing the auction \npending FERC’s decision on the matter.  If the Office of the Interconnection disagrees with the \nMarket Monitoring Unit’s determination and does not apply to FERC for an order directing the \nCapacity Market Seller to participate in the auction or for other appropriate relief, the Market \nMonitoring Unit may exercise its powers to inform Commission staff of its concerns and to seek \nappropriate relief. \n \n \n(j) \nAn RBP Resource committed through the Reliability Backstop Procurement must \noffer all available committed RBP UCAP MW as a price-taker (i.e., $0/MW-day) into the \napplicable RPM Auctions pursuant to the capacity must offer requirements and exceptions set \nforth in Tariff, Attachment DD, sections 6.6 and 6.6A.  The applicable RPM Auctions shall be \nthe Base Residual Auctions and Incremental Auctions conducted after an RBP Resource’s RBP \nUCAP MW have been committed through the Reliability Backstop Procurement and continuing \nfor each subsequent Delivery Year through the end of the fixed 15-year term, except RBP UCAP \nMW for RBP Resources without a notice of intent to offer submitted pursuant to Tariff, \nAttachment DD, section 5.5 for the 2029/2030 Base Residual Auction, which shall have a must \noffer requirement beginning in the next RPM Auction, including but not limited to the \n2030/2031 Base Residual Auction and the 2029/2030 Second Incremental Auction."},{"page":99,"startToken":39155,"endToken":39725,"text":"6.6A Offer Requirement for Capacity Performance Resources \n \n \n(a) \nThe installed capacity of every Existing Generation Capacity Resource located in \nthe PJM Region that is capable (or that reasonably can become capable) of qualifying as a \nCapacity Performance Resource shall be offered as a Capacity Performance Resource by the \nCapacity Market Seller that owns or controls all or part of such resource (which may include \nsubmission as Self-Supply) in all RPM Auctions for each such Delivery Year, less any amount \ndetermined by the Office of the Interconnection to be eligible for an exception to the Capacity \nPerformance Resource must-offer requirement, where installed capacity is determined as of the \ndate on which bidding commences for each RPM Auction pursuant to Tariff, Attachment DD, \nsection 5.6.6.  A Planned Generation Capacity Resource associated with a notice of intent to \noffer submitted pursuant to Tariff, Attachment DD, section 5.5 shall be required to be offered by \nthe Capacity Market Seller of such resource in the relevant RPM Auction. \n \n \n(b) \nDeterminations of EFORd, Accredited UCAP, and Unforced Capacity made \nunder this Tariff, Attachment DD, section 6.6 as to a Generation Capacity Resource shall govern \nthe offers required under this section as to the same Generation Capacity Resource.   \n \n \n(c) \nExceptions to the requirement in subsection (a) shall be permitted only for a \nresource which the Capacity Market Seller demonstrates is reasonably expected to be physically \nincapable of satisfying the requirements of a Capacity Performance Resource.  Through the \n2025/2026 Delivery Year, Intermittent Resources, Capacity Storage Resources, Hybrid \nResources consisting exclusively of components that in isolation would be Intermittent \nResources or Capacity Storage Resources, Demand Resources, and Energy Efficiency Resources \nshall not be required to offer as a Capacity Performance Resource, but shall not be precluded \nfrom being offered as a Capacity Performance Resource at a level that demonstrably satisfies \nsuch requirements.  Beginning with the 2026/2027 Delivery Year, Demand Resources shall not \nbe required to offer as a Capacity Performance Resource, but shall not be precluded from being \noffered as a Capacity Performance Resource at a level that demonstrably satisfies such \nrequirements.  Notwithstanding the foregoing, nothing herein provides a defense to a claim of \nwithholding, market manipulation, or the exercise of market power by any entity who is \naffiliated with or are under common ownership or control of a Capacity Market Seller that does \nnot offer Demand Resources into a Reliability Pricing Model Auction.  Exceptions shall be \ndetermined using the same timeline and procedures as specified in section 6.6.  \n \nEffective with the 2023/2024 Delivery Year, Capacity Market Sellers seeking an \nexception for a Base Residual Auction on the basis that a resource is incapable of meeting the \nCapacity Performance Resource requirement shall include a documented plan with the \nsubmission of their request showing the steps the Capacity Market Seller intends to pursue for \nthe resource to become physically capable of satisfying the requirements of a Capacity \nPerformance Resource.  Such plan shall include (i) a timeline for design, permitting, \nprocurement, and construction milestones, as applicable, where such timeline shall not exceed \none Base Residual Auction exception, and (ii) evidence of corporate commitment (e.g., an SEC \nfiling, a press release, or a letter from a duly authorized corporate officer indicating intent to \nmake such investment).  Periodic updates on the progress, shall be provided by the Capacity \nMarket Seller to the Office of the Interconnection and the Market Monitoring Unit for their"},{"page":100,"startToken":39725,"endToken":40254,"text":"review by no later than (i) one hundred twenty (120) days prior to the commencement of the \noffer period for subsequent Incremental Auctions for the applicable Delivery Years, and (ii) the \nDecember 1 that last precedes subsequent Base Residual Auctions.  The Capacity Market Seller \nshall also immediately notify the Office of the Interconnection and the Market Monitoring Unit \nof any material changes to the plan that may occur.  Upon request by a Capacity Market Seller, a \none year extension to the plan timeline shall be permissible only for delays not caused by the \nCapacity Market Seller, and that could not have been remedied through the exercise of due \ndiligence by the Capacity Market Seller. In no event may an exception be requested by the \nCapacity Market Seller for more than two Base Residual Auctions. \n \nFailure to submit a documented plan, or lack of good faith effort by a Capacity Market \nSeller to make an Existing Generation Capacity Resource physically capable of meeting the \nrequirements of a Capacity Performance Resource in accordance with a documented plan, shall \nresult in the removal of the resource’s Capacity Resource status effective with the first future \nDelivery Year for which the resource was granted an exception, no earlier than the 2023/2024 \nDelivery Year.   The Office of the Interconnection shall amend the applicable Interconnection \nService Agreement or wholesale market participation agreement to reflect any such removal of \nthe Capacity Interconnection Rights, and shall report the amended agreement to the Commission \nin the same manner as the original (e.g. FERC Filing or Electronic Quarterly Reports).  The \nOffice of the Interconnection shall file the amended agreement unexecuted if the Interconnection \nCustomer or wholesale market participant does not sign the amended Interconnection Service \nAgreement or wholesale market participation agreement. The required change in Capacity \nResource status shall only apply to those Generation Capacity Resources that are shown to be \nphysically incapable of satisfying the requirements of a Capacity Performance Resource. \n \n \n(d) \nA resource not exempted or excepted under subsection (c) hereof that is capable \nof qualifying as a Capacity Performance Resource and does not offer into an RPM Auction as a \nCapacity Performance Resource shall be subject to the same restrictions on subsequent offers, \nand other possible remedies, as specified in section 6.6. \n \n \n(e) \nAn RBP Resource committed through the Reliability Backstop Procurement must \noffer all committed RBP UCAP MW as price-takers (i.e., $0/MW-day) into the applicable RPM \nAuctions pursuant to the capacity must offer requirements and exceptions set forth in Tariff, \nAttachment DD, sections 6.6 and 6.6A.  The applicable RPM Auction shall be the Base Residual \nAuctions conducted after an RBP Resource’s RBP UCAP MW have been committed through the \nReliability Backstop Procurement and continuing for each subsequent Delivery Year through the \nend of the fixed 15-year term, except RBP UCAP MW for Capacity Performance Resources \nwithout a notice of intent to offer submitted pursuant to Tariff, Attachment DD, section 5.5 for \nthe 2029/2030 Base Residual Auction, which shall have a must offer requirement beginning in \nthe next RPM Auction, including but not limited to the 2030/2031 Base Residual Auction and \nthe 2029/2030 Second Incremental Auction."},{"page":101,"startToken":40254,"endToken":40720,"text":"16. \nRELIABILITY BACKSTOP  \n \n16.1. Purpose \n \nThe Reliability Backstop provides a mechanism to resolve reliability criteria violations caused \nby: (a) lack of sufficient capacity committed through the Reliability Pricing Model Auctions; or \n(b) near-term transmission deliverability violations identified after the Base Residual Auction is \nconducted.  These backstop mechanisms are intended to guarantee that sufficient generation, \ntransmission and demand response solutions will be available to preserve system reliability.  The \nbackstop mechanisms are based on specific triggers that signal a need for a targeted solution to a \nreliability problem that was not resolved by the long-term commitment of Capacity Resources \nthrough Self-Supply or the Reliability Pricing Model Auctions.   \n \n16.2 \nInvestigation of Capacity Shortfall \n \nBeginning with the 2032/2033 Delivery Year and thereafter, if the total Unforced Capacity of \nCapacity Resources committed for a Delivery Year following the Base Residual Auction equates \nto an installed reserve margin that is more than one percentage point lower than the approved \nPJM Region Installed Reserve Margin, the Office of the Interconnection shall investigate the \ncause for the shortage, and recommend corrective action, including, without limitation, adjusting \nthe Cost of New Entry to the extent determined necessary by such investigation, or addressing \nother barriers to entry identified by such investigation.  No Reliability Backstop Auction will be \nconducted to address such a shortfall unless it occurs in the Base Residual Auctions for three \nconsecutive Delivery Years beginning with the 2032/2033 Delivery Year and thereafter.  \n \n16.3 \nTriggering Conditions \n \n \na) \nEither of the following two conditions will trigger reliability backstop measures \nprovided in this section, as described below: \n \ni) \nIf the total Unforced Capacity of all Capacity Resources committed \nthrough Self-Supply or the Base Residual Auctions for three consecutive Delivery Years \nbeginning with the 2032/2033 Delivery Year and thereafter, equates to an installed reserve \nmargin that is more than one percentage point lower than the approved PJM Region Installed \nReserve Margin, the Office of the Interconnection will declare a capacity shortage and make a \nfiling with FERC for approval to conduct a Reliability Backstop Auction.  Upon receipt of such \napproval, the Office of the Interconnection will conduct a Reliability Backstop Auction in \naccordance with ection 16.4 below. \n \nii) \nIf the total Unforced Capacity of all Base Load Generation Resources \ncommitted in a Base Residual Auction for a Delivery Year is less than the forecasted minimum \nhourly load calculated by the Office of the Interconnection for such Delivery Year, the Office of \nthe Interconnection will investigate the cause of shortfall.  If such a shortfall occurs in the Base \nResidual Auctions for three consecutive Delivery Years beginning with the 2032/2033 Delivery \nYear and thereafter, the Office of the Interconnection shall declare a capacity shortage and make \na filing with FERC for approval to conduct a Reliability Backstop Auction.  Upon receipt of such"},{"page":102,"startToken":40720,"endToken":41154,"text":"approval, the Office of the Interconnection will conduct a Reliability Backstop Auction in \naccordance with section 16.4 below.  \n \n \nb) \nIn addition to the foregoing events that trigger reliability backstop measures, if a \nnear-term, i.e., later in time than the conduct of the Base Residual Auction for a Delivery Year, \ntransmission criteria violation caused by an announced generation resource deactivation is \nidentified by the regional transmission reliability planning analysis performed by the Office of \nthe Interconnection in accordance with Part V of this Tariff, the Office of the Interconnection \nwill identify the necessary transmission upgrade. In accordance with such rules, such generation \nresource may remain in service until the transmission upgrade is installed.  No Reliability \nBackstop Auction will be conducted. \n \n16.4. Reliability Backstop Auction \n \n \na) \nScope of Auction  \n \nThe Office of the Interconnection shall conduct each Reliability Backstop Auction to commit \nadditional Generation Capacity Resources, or in the case of an auction triggered by section \n16.3(a)(ii), additional Base Load Generation Resources to the PJM Region to resolve the system-\nwide reliability criteria violation that triggered the need for such auction.  Capacity Resources \ncommitted in a Reliability Backstop Auction for a Delivery Year shall not include any Planned \nGeneration Capacity Resources previously committed in the Base Residual Auction for such \nDelivery Year.  The Reliability Backstop Auction shall obtain commitments of additional \nGeneration Capacity Resources (or, as applicable, additional Base Load Generation Resources) \nfor a term of up to fifteen (15) Delivery Years.  If a Reliability Backstop Auction is required, the \noffer period for such auction shall commence, subject to FERC approval as specified above, no \nlater than four months after the Base Residual Auction in which the third consecutive Capacity \nResource shortfall occurs. Upon verification and notification by the PJM Board of Managers that \na Reliability Backstop Auction is required, the Office of the Interconnection shall post \nnotification that a Reliability Backstop Auction is to be held.  Upon such notification, the offer \nperiod shall commence, and shall remain open for six (6) months.  PJMSettlement shall be the \nCounterparty to the capacity transaction resulting from committed Capacity Resources clearing \nthe Reliability Backstop Auction. \n \n \nb) \nSell Offers \n \nEach Sell Offer shall specify the following information, as further specified in the PJM Manuals: \n \n• \nthe minimum price in $/MW-day required by the Capacity Market Seller to \nprovide additional Unforced Capacity from a Generation Capacity Resource (or \nfrom a Base Load Generation Resource, in the case of an auction triggered by \nsection 16.3(a)(ii)) above; \n \n• \nthe megawatts of Unforced Capacity to be provided by such resource;  \n \n• \nthe specific location of the proposed plant;"},{"page":103,"startToken":41154,"endToken":41465,"text":"• \nall information required from a Generation Interconnection Customer by Tariff, \nPart IV and the PJM Manuals;  \n \n• \ngeneral plant technical specifications, as specified in the PJM Manuals; \n \n• \nthe term of cost recovery (“Backstop Period”) requested, not to exceed 15 years; \nand   \n \n• \nthe first full Delivery Year for which such resource shall be available, which shall \nalso be the first year of the Backstop Period. \n \nEach Generation Capacity Resource (or Base Load Generation Resource) accepted in a \nReliability Backstop Auction shall comply with the procedures for new generation \ninterconnection in Tariff, Part IV, and each such resource shall be responsible for satisfying all \ncapability and deliverability requirements for Capacity Resources, pursuant to the Reliability \nAssurance Agreement.  \n \n \nc) \nSubmission of Sell Offers \n \nThe Sell Offer period shall begin at 00:01 Eastern Prevailing Time on the date specified by the \nOffice of the Interconnection in the notification posting and shall end at 23:59 Eastern Prevailing \nTime six calendar months after such date.  Sell offers shall be submitted during such period in \nwriting to the Office of the Interconnection, and shall conform to the submission procedures as \nspecified in the PJM Manuals.  The Office of the Interconnection shall confirm in writing the \nreceipt of each Sell Offer, within two weeks after receipt of each such offer. \n \n \nd) \nPosting of Information by the Office of the Interconnection  \n \nUpon notification by the PJM Board of Managers that a Reliability Backstop Auction will be \nconducted, the Office of the Interconnection shall post the following information: \n \n• \nSystem condition that necessitates a Reliability Backstop Auction; \n \n• \nMegawatt quantity of Unforced Capacity required from additional Generation \nCapacity Resources, or from additional Base Load Generation Resources;  \n \n• \nDate by which the resources must be capable of delivering Unforced Capacity; \n \n• \nAny other required specifications for the additional Unforced Capacity sought \nthrough such auction. \n \n \ne) \nConduct of the Reliability Backstop Auction \n \n \n \ni) \nAuction Clearing Procedure"},{"page":104,"startToken":41465,"endToken":41953,"text":"The Reliability Backstop Auction shall select the Sell Offer or combination of Sell Offers that \nthat satisfies the requirements posted by the Office of the Interconnection at the lowest offer \nprice(s).  If more than one Sell Offer must be selected to satisfy the specified requirements, the \nSell Offers shall be selected in rank order from lowest offer price to highest offer price until the \nrequirement is satisfied.  In the event two or more Sell Offers specify the same offer price, and \nfewer than all of such offers are needed to satisfy the specified requirements, the Office of the \nInterconnection shall select the Sell Offer(s) proposing Generation Capacity Resource(s), or, as \napplicable, Base Load Generation Resource(s) that will best satisfy overall reliability \nrequirements for the PJM Region, as determined by the Office of the Interconnection using \ntransmission reliability analysis.  \n \n \n \nii) \nMarket Settlement \n \nPursuant to the agreement specified below, each Capacity Market Seller submitting a Sell Offer \nthat is accepted in a Reliability Backstop Auction shall be paid by PJMSettlement the offer price \nin such Sell Offer for each MW-day in the Backstop Period, less any payments the Capacity \nMarket Seller is entitled to receive pursuant to Tariff, Attachment DD, section 5 as a result of \nSell Offers submitted with respect to such Generation Capacity Resource in any Base Residual \nAuction or Incremental Auction, including, without limitation, payments of Capacity Resource \nClearing Prices (including for Self-Supply) and Resource Make-Whole Payments; and less any \npayments the Capacity Market Seller is entitled to receive for energy or ancillary services \npursuant to Operating Agreement, Schedule 1 with respect to services provided by such resource, \nnet of the Variable Operations and Maintenance costs of such resource, as determined in \naccordance with the PJM Manuals.  \n \nPJM shall recover the costs of any such payments to Capacity Market Sellers for such resources \nthrough a charge, in addition to the Locational Reliability Charge, assessed on all LSEs in the \nPJM Region, pro rata based on each such LSE’s Daily Unforced Capacity Obligations in all \nLDAs in which such LSE serves load.  PJMSettlement shall be the Counterparty to the LSE’s \nobligation to pay, and payment of, such charges. \n \n \n \niii) \nStandard Contract Provisions \n \nPJMSettlement, will enter into an agreement with each Capacity Market Seller that submitted an \naccepted Sell Offer in any Reliability Backstop Auction providing for the payments specified \nabove.  Such agreement shall include the provisions and address the standards set forth in section \n16.4(b) above, and shall include such other terms and conditions as are customary in the \nindustry, as specified in the PJM Manuals. \n \n \nf) \nFERC Approval  \n \nAny such agreement shall provide that it shall be filed with FERC as a rate schedule pursuant to \nsection 205 of the Federal Power Act, and that the effectiveness of such agreement shall be \nconditioned on receipt of FERC acceptance or approval of such agreement. \n \n16.5 \nMust Offer into Base Residual Auction"},{"page":105,"startToken":41953,"endToken":42171,"text":"All Capacity Market Sellers submitting a Sell Offer that is selected in a Reliability Backstop \nAuction must offer all Unforced Capacity of the Generation Capacity Resource underlying such \nSell Offer into the Base Residual Auctions conducted subsequent to the Reliability Backstop \nAuction for all Delivery Years in the Backstop Period.  The Market Seller shall offer the \nUnforced Capacity of such resources into each such auction at zero price, and shall receive the \nCapacity Resource Clearing Price as determined in each such auction. \n \n16.6 \nReliability Backstop Resource Deficiency Charges \n \n \n(a) \nAny Capacity Market Seller that submits a Sell Offer that was selected in a \nReliability Backstop Auction and that is not able to deliver in a Delivery Year all megawatts of \nUnforced Capacity specified in the selected Sell Offer, shall not receive any payments that such \nCapacity Market Seller otherwise would have been eligible to receive for such Delivery Year \npursuant to the Reliability Backstop Auction. \n \n \n(b) \nAny Capacity Market Seller that submits a Sell Offer that was selected in a \nReliability Backstop Auction and that fails to deliver all megawatts of Unforced Capacity \nspecified in the selected Sell Offer at any time during the Backstop Period specified in such Sell \nOffer must refund all payments received by such Market Seller pursuant to section 16.4(b) \nabove."},{"page":106,"startToken":42171,"endToken":42214,"text":"18.  \nRELIABILITY BACKSTOP PROCUREMENT \n \nThe Reliability Backstop Procurement or “RBP” is a one-time procurement, starting in 2026, to \naddress resource adequacy challenges in the PJM Region arising from insufficient capacity \ncommitted through Reliability Pricing Model Auctions starting in the 2027/2028 Delivery Year."},{"page":107,"startToken":42214,"endToken":42587,"text":"18.1  Determination of Final RBP Target \n \nThe Reliability Backstop Procurement is designed to procure sufficient RBP UCAP MW to meet \nthe Final RBP Target.   \n \n(a) \nInitial RBP Target  \nThe Initial RBP Target shall be a region-wide value equal to the UCAP MW quantity PJM clears \nshort of the PJM Region Reliability Requirement for the 2028/2029 Delivery Year Base Residual \nAuction.   \n \n(b) \nFinal RBP Target  \nThe Final RBP Target shall be a PJM region-wide value equal to the Initial RBP Target minus the \ntotal PJM region-wide Qualifying RBP Offset UCAP MW and the unforced capacity obligation \nvalue of load that have successfully requested and obtained an opt-out pursuant to Tariff, \nAttachment DD, section 18.1(d).    \n \n(c) \nFixed Resource Requirement Entities \nFixed Resource Requirement (“FRR”) Entities as of the 2028/2029 Delivery Year shall be \nexcluded from the Reliability Backstop Procurement, including Initial and Final RBP Targets.   \nTo the extent an Electric Distributor zone/area that has RBP UCAP MW committed through the \nReliability Backstop Procurement later becomes an FRR Service Area pursuant to RAA, Schedule \n8.1.D, the Electric Distributor zone/area shall continue to be accountable for the RBP UCAP MW \nquantity committed through the Reliability Backstop Procurement.   \n \n(d) \nOpt-Out  \nWhen calculating the Final RBP Target, the Initial RBP Target shall also be decremented where \nthe Electric Distributor’s zone/area has rates that are not regulated by the states and is unable to \naddress cost allocation associated with capacity procured in the backstop. Such request by the \nElectric Distributor shall specify the associated MW quantity of load in the zone/area that will be \nopted-out of the Initial RBP Target and be accompanied by supporting documentation \ndemonstrating an inability to address cost allocation associated with capacity procured in the \nbackstop, along with written support for such opt-out from the relevant state governor, RERRA, \nand interconnection customer(s). The Initial RBP Target shall be further decremented, if requested \nby an Electric Distributor, by up to the associated MW quantity of load that participates in a peak \nshaving adjustment program where such Electric Distributor’s zone/area addresses their capacity \nneeds through peak shaving adjustment programs that are codified in state law and that also meet \nthe requirements of Tariff, Attachment DD-2."},{"page":108,"startToken":42587,"endToken":43088,"text":"18.2 \nQualifying RBP Offset UCAP MW   \n \n(a) \nQualifying RBP Offset UCAP MW is capacity that (i) has not previously supported \na capacity commitment or been committed in an FRR Plan as of the commencement of the \nReliability Backstop Procurement; and (ii) is supplied by a resource that satisfies each of the \ncriteria set forth in Tariff, Attachment DD, section 18.2(b).   \n \n(b) \nResources Eligible to Supply Qualifying RBP Offset UCAP MW \n \nA resource eligible to supply Qualifying RBP Offset UCAP MW must have an expected \ncommercial operation date, or is reasonably expected to be an Annual Demand Resource or DER \nCapacity Aggregation Resource that will be registered with the Office of the Interconnection and \nunder a contract to perform based on PJM dispatch instructions, by no later than June 1, 2032 and \nbe: (i) a new build generation resource including new resources that obtain Capacity \nInterconnection Rights transferred from deactivated resources or resources that have announced \ndeactivation as of April 10, 2026; (ii) the incremental capacity created by an uprate of existing \nGeneration Capacity Resources, but only to the extent such incremental capacity is created through \nan increase in such Generation Capacity Resource’s installed capacity and increase in Capacity \nInterconnection Rights associated with that Generation Capacity Resource; (iii) the incremental \ncapacity created by the utilization of Surplus Interconnection Service; (iv) repowering of a \ndeactivated generation resource that deactivated prior to April 10, 2026; (v) incremental capacity, \nwhether due to greater Unforced Capacity or a higher level of Capacity Interconnection Rights, \ncreated by an existing Generation Capacity Resource’s changing fuel type to a more efficient fuel \ntype; or (vi) Planned Demand Resource or Planned DER Capacity Aggregation Resources, as \ndescribed in the RAA, Schedule 6 and Schedule 6.2. \n \n(c) \nEvidence of Qualifying RBP Offset UCAP MW  \n \nDuring the RBP bid submission window defined in Tariff, Attachment DD, section 18.4, Electric \nDistributors shall report the Qualifying RBP Offset UCAP MW in their respective zones/areas to \nthe Office of the Interconnection in accordance with their requirements set forth in the Operating \nAgreement, section 11.3, and such report shall be accompanied by evidence of at least one of the \nfollowing supporting materials.  Likewise, to the extent LSEs, interconnecting customers, large \nloads, Transmission Owners, or other entities report Qualifying RBP Offset UCAP MW to the \nOffice of the Interconnection during such RBP bid submission window, the reported Qualifying \nRBP Offset UCAP MW must be accompanied with evidence of at least one of the following \nsupporting materials: \n \n(i) \nSigned bilateral contracts for Qualifying RBP Offset UCAP MW for at least \nfive Delivery Years with a commercial operation date prior to the start of the 2032/2033 \nDelivery Year, and matched with load that has an executed electric service agreement or \ntransmission service agreement, indicating that the load will be coming online in the \n2027/2028 or 2028/2029 Delivery Year; \n \n(ii) \nSelf-Supply generation that is in a Relevant Electric Retail Regulatory \nAuthority (“RERRA”)-approved or accepted integrated resource plan with either"},{"page":109,"startToken":43088,"endToken":43374,"text":"associated generation in the PJM interconnection queue or signed bilateral contracts for \nQualifying RBP Offset UCAP MW for at least five Delivery Years with a commercial \noperation date prior to the start of the 2032/2033 Delivery Year, and matched with load \nthat has an executed electric service agreement or transmission service agreement, \nindicating that the load will be coming online in the 2027/2028 or 2028/2029 Delivery \nYear; or \n \n(iii) \nSigned commitment between a Curtailment Service Provider or DER \nAggregator and new load(s) that has an executed electric service agreement or transmission \nservice agreement, indicating that the new load(s) will, in a MW quantity equal to MW \nquantity of the new load(s), either (a) participate as Annual Demand Resources or DER \nCapacity Aggregation Resources starting in the 2028/2029 Delivery Year Second \nIncremental Auction and continuing through the 2032/2033 Delivery Year, or (b) purchase \nreplacement Qualifying RBP Offset UCAP MW that are eligible generation or storage \nresources.  \n \n(d) \nTo determine the quantity of any Qualifying RBP Offset UCAP MW that are \nverified by the Office of the Interconnection and used to decrement the Initial RBP Target, the \nOffice of the Interconnection shall use the applicable ELCC Class Ratings from the Base Residual \nAuction associated with the 2028/2029 Delivery Year, or the estimated unit-specific UCAP value \nfor resources with no ELCC Class Rating. \n \n(e) \nThe total quantity of Qualifying RBP Offset UCAP MW verified by the Office of \nthe Interconnection and used to decrement the Initial RBP Target total amount allowed for each \nzone/area will be capped at the Load Adjustment for each Electric Distributor zone/area amount \nof summer 2028 demand as set forth in the load forecast."},{"page":110,"startToken":43374,"endToken":43829,"text":"18.3 \n Cost Allocation of RBP Charges, Credits, and Shortfall Charges \n \n(a) \nCost Allocation to Electric Distributor zone/area \n \nThe Office of the Interconnection shall allocate the Initial RBP Target MW to each Electric \nDistributor’s zone/area using that zone/area’s pro-rata share of the difference between the \nforecasted Load Adjustments for the 2026/2027 Delivery Year and the 2028/2029 Delivery Year.     \n \nThe difference between the forecasted Load Adjustments for the 2026/2027 and the 2028/2029 \nDelivery Years shall be reduced for the purpose of this calculation to the extent:  \n \n(i) \nan Electric Distributor, LSE, Transmission Owner, or other entity provides \nthe Office of Interconnection with evidence of Qualifying RBP Offset UCAP MW, in \naccordance with Tariff, Attachment DD, section 18.2 and as may be further set forth in the \nPJM Manuals; or  \n \n(ii) \nan Electric Distributor zonee/area meets one of the opt-out provisions set \nforth in accordance with Tariff, Attachment DD, section 18.1(d). \n \nThe resulting reduced MW, floored at zero, is used to calculate the zone/area’s assigned pro-rata \nshare of the Final RBP Target MW.  The zone/area’s assigned share of the Final RBP Target MW \nshall remain constant throughout the fixed, 15-year term. \n \nThe Office of the Interconnection shall allocate the total RBP Charges, assessed daily, to an \nElectric Distributor’s zone/area on a pro-rata basis using the zone/area’s assigned share of the total \nFinal RBP Target MW across all zone/areas.  \n \n(b) \nCost Allocation to Load Serving Entities \n \n(i) \nThe daily assessed RBP Charges allocated to each Electric Distributor \nzone/area shall be further allocated to each applicable LSE within that zone/area with an \nRBP Obligation (“RBO”) based on the LSE’s pro-rata share of the total RBP Obligation \nMW for the zone/area.    \n \n(ii) \nThe RBP Charge assessed daily to an LSE in a zone/area shall be the LSE’s \ndaily reported RBO MW in the zone/area divided by the total RBO MW in the zone/area \nmultiplied by total, daily RBP Charges allocated to the zone/area.   \n \n(iii) \nThe RBO MW shall be, where available, the state and/or RERRA-\ndetermined allocation of cleared RBP UCAP MW to LSEs within each Electric \nDistributor’s zone/area, as reported by each Electric Distributor to the Office of the \nInterconnection, with the initial allocation reported no later than sixty (60) days prior to \nthe 2028/2029 Delivery Year.  If no RBO MW are reported to the Office of the \nInterconnection in an Electric Distributor zone/area, PJM will allocate the RBP Charges \nfor that zone/area to all load in the zone/area using each LSE’s ratio share of the Daily \nUnforced Capacity Obligation for the zone/area as determined in RAA, Schedule 8."},{"page":111,"startToken":43829,"endToken":43873,"text":"PJMSettlement shall be the Counterparty to each LSE’s obligation to pay, and payments \nof, RBP Charges.  \n \n(iv) \nRBP Shortfall Charges will be allocated to LSEs as credits based on using \nthe same pro-rata share of the RBP Charges, pursuant to RAA, Section 7.2B."},{"page":112,"startToken":43873,"endToken":44130,"text":"18.4  Scope of the Reliability Backstop Procurement  \n \nThe Office of the Interconnection shall conduct an RBP to commit RBP Resources up to the UCAP \nMW value to meet the Final RBP Target.  The Reliability Backstop Procurement offer submission \nwindow for RBP Sell Offers shall open for three weeks in 2026.  The clearing and selection process \nwill take place thereafter and concluding six weeks following the close of the offer submission \nwindow.  The Office of the Interconnection shall notify RBP Sellers that receive a commitment as \nan RBP Resource as soon as practicable upon the conclusion of the RBP.  The Office of the \nInterconnection shall post specific dates on the PJM website prior to the commencement of the \nReliability Backstop Procurement.     \n \nRBP Sellers may submit RBP Sell Offers of RBP Resources supporting RBP UCAP MW into the \nReliability Backstop Procurement.  PJMSettlement shall be the Counterparty to the transactions \narising from the RBP.   \n \nAn RBP Sell Offer will be considered binding once any PJM-identified deficiencies are cured and \nuntil the conclusion of the Reliability Backstop Procurement and the underlying resource does not \nreceive a commitment in the Reliability Backstop Procurement.   \n \nThe Reliability Backstop Procurement shall offer commitments for RBP UCAP MW for a fixed \nperiod of fifteen (15) Delivery Years, starting with the 2028/2029 Delivery Year.  Resources with \na commercial operation date later than the 2028/2029 Delivery Year shall be committed for the \nremainder of the fifteen-year term of the Reliability Backstop Procurement commitment period, \ni.e. through the end of the 2042/2043 Delivery Year."},{"page":113,"startToken":44130,"endToken":44517,"text":"18.5  The Reliability Backstop Procurement Process \n \n(a) \nRBP Seller Eligibility to Participate and General Requirements for Resources \nSupporting RBP UCAP MW \n \nTo be eligible to participate in the Reliability Backstop Procurement, an RBP Seller must meet the \nRBP credit requirements, set forth in Tariff, Attachment DD, section 18.8, with RBP Sell Offer(s) \nfor RBP UCAP MW based on a resource that:  \n \n(i) \nHas a commercial operation date, or is reasonably expected to be an Annual \nDemand Resource or DER Capacity Aggregation Resource that will be registered with the \nOffice of the Interconnection and under a contract to perform based on PJM dispatch \ninstructions, by no later than June 1, 2032, inclusive of any required Network Upgrades;  \n \n(ii) \nHas not received a capacity commitment or been committed in an FRR Plan \nas of the commencement of the Reliability Backstop Procurement; \n \n(iii) \nIs not supplying Qualifying RBP Offset UCAP MW; \n \n(iv) \nTo the extent the subject of a notice of intent for the 2028/2029 Base \nResidual Auction, must have offered and not cleared in the 2028/2029 Base Residual \nAuction; \n \n(v) \nTo the extent the subject of a notice of intent for the 2029/2030 Base \nResidual Auction, must be offered into the 2029/2030 Base Residual Auction; and \n \n(vi) \nMeets the requirements in Tariff, Attachment DD, sections 18.5(b), 18.5(c), \nor 18.5(d). \n \n(b) \nGeneration or Energy Storage Resources as an RBP Resource \n \nTo qualify as an RBP Resource, a generation or Energy Storage Resource that supplies RBP UCAP \nMW eligible to be offered into the Reliability Backstop Procurement shall be in the PJM Region \nor meet the requirements to pseudo-tie into the PJM Region in Tariff, Attachment DD, section \n5.5A(b), must meet the requirements of Tariff, Attachment DD, section 18.5(a) and must be: \n \n(i) \nComposed of new Installed Capacity and new Maximum Facility Output; \n \n(ii) \nSupported by new Capacity Interconnection Rights (if located in the PJM \nRegion) or Capacity Interconnection Rights transferred from a deactivated resource or a \nresource that announced deactivation as of April 10, 2026; and \n \n(iii) \nConsist of (1) new build; (2) incremental capacity created by an uprate of \nan existing Generation Capacity Resource’s or Energy Storage Resource’s installed \ncapacity and associated level of Capacity Interconnection Rights; or (3) repowering of a"},{"page":114,"startToken":44517,"endToken":44888,"text":"generation resource that had deactivated, or announced deactivation, on or before April 10, \n2026. \n \n(c) \nRBP Demand Resources \n \nTo qualify as a Demand Resource that supplies RBP UCAP MW eligible to be offered into the \nReliability Backstop Procurement, a Demand Resource must meet the requirements of Tariff, \nAttachment DD, sections 18.5(a), and:  \n \n(i) \nNot be reliant on or composed of registered location(s) that previously \nsupported a Demand Resource that provided capacity in a prior Delivery Year unless such \nlocation represents an incremental increase in capacity resulting from an investment in new \ngeneration or new storage resources at that location; and    \n \n(ii) \nIdentify, as part of its RBP Sell Offer, for the full length of the fixed term, \nthe location(s) and associated participation contract(s). \n \n(d)  \nRBP DER Aggregation Resources \n \nTo qualify as a DER Capacity Aggregation Resource that supplies RBP UCAP MW eligible to be \noffered into the Reliability Backstop Procurement, a Planned DER Capacity Aggregation Resource \nmust meet the requirements of Tariff, Attachment DD, sections 18.5(b) and:  \n \n(i) \nIdentify, as part of its RBP Sell Offer, for the length of the fixed term, the \nlocation(s) and associated participation contract(s).  \n \n(e) \nRBP Sell Offers \n \nRBP Sell Offers for RBP UCAP MW shall specify an offer quantity in UCAP MW and an offer \nprice in $/MW-day UCAP for each Delivery Year beginning with the first full Delivery Year in \nwhich the RBP UCAP MW is expected to provide capacity through the end of the fixed 15-year \nterm.   \n \nRBP Sellers will be responsible for all actual Network Upgrade costs as determined through the \ninterconnection process, without subsequent adjustments to RBP Sell Offers.   \n \nEach RBP Sell Offer shall include the following information for the RBP UCAP MW offered: \n \n(i) \nthe MW of UCAP to be provided by such resource for each Delivery Year, \nwhere the maximum UCAP included in an RBP Sell Offer shall be limited to no greater \nthan 120% of the resource type’s most recent maximum Preliminary ELCC Class Ratings \nfor 2028/2029 through the last posted Delivery Year or based on the resource’s maximum \nestimated unit-specific ELCC ratings across such period for resources with no ELCC Class \nRating, multiplied by the resource’s ICAP;"},{"page":115,"startToken":44888,"endToken":45265,"text":"(ii) \nthe price in $/MW-day UCAP for each Delivery Year beginning with the \nfirst full Delivery Year in which the RBP UCAP MW is expected to provide capacity \nthrough the end of the fixed 15-year term;         \n \n(iii) \nthe first full Delivery Year for which such resource shall be available and \noffering to provide capacity;  \n \n(iv) \nall relevant documentation necessary for the Office of the Interconnection \nto evaluate whether the project satisfies the gating criteria, as set forth in Tariff, Attachment \nDD, section 18.5(f)(i). \n \n(f) \nClearing Structure \n \nFollowing the closing date of bid solicitation for the Reliability Backstop Procurement in October \n2026, the Office of the Interconnection shall complete the Reliability Backstop Procurement in \ntwo stages: (1) gating criteria evaluation and (2) selection assessment, with notification of finalized \ncommitments posted prior to the Base Residual Auction for the 2029/2030 Delivery Year. The \nReliability Backstop Procurement shall be pay-as-bid.  \n \n(i) \nStage 1: Gating Criteria Evaluation \n \nA valid RBP Sell Offer shall include the information and evidence required by this section.  \nThe Office of the Interconnection shall evaluate all RBP Sell Offers for compliance with \nthis requirement.  Such evaluation shall be conducted by the Office of the Interconnection \non a pass/fail basis.   \n \nRBP Sell Offers that do not include the following information shall not proceed to selection \nassessment, provided, however, that the Office of the Interconnection shall provide the \nRBP Seller the opportunity to cure any identified deficiencies within five (5) calendar days. \nNotwithstanding, such opportunity to cure shall not extend past the close of the bid \nsubmission window of the Reliability Backstop Procurement. \n \nRBP Sell Offers for RBP Generation and/or Storage Capacity Resources must be \naccompanied by:   \n \n(1) \nA critical path construction schedule and expected commercial \noperation date, with attestation, for the Office of the Interconnection to validate that \nRBP Sell Offers are for RBP UCAP MW with a feasible commercial operation date \nof June 1, 2032 or earlier;   \n \n(A) \nWith respect to a project in Transition Cycle #2 under Tariff, \nPart VII and earlier, such project must provide study information and \ntimeline from its most current PJM study;  \n \n(B) \nWith respect to a project in Cycle 1 under Tariff Part VIII, \nthe Expedited Interconnection Track under Tariff, Part X, or not under"},{"page":116,"startToken":45265,"endToken":45638,"text":"study, the project must provide study information and timeline from an \nindependent consultant report; \n \n(2) \nEvidence of 100% Site Control for each of the Generating Facility \n(including the location of the main step-up transformer), the Interconnection \nFacilities, and the Interconnection Switchyard (as defined in the PJM Manuals) for \na term of at least three years from the date of submission of the Application. \n \nIn addition, a certification, executed by an officer or authorized representative of \nthe Generation Project Developer, verifying that the Site Control requirements have \nbeen met. Further, at Transmission Provider’s request, Generation Project \nDeveloper shall provide copies of landowner attestations or county recordings. The \nSite Control requirements include an acreage requirement for the Project, as set \nforth in the PJM Manuals. \n \n \nEvidence of site control shall be consistent with Tariff, Part VIII, Subpart A, section \n402;  \n \n(3) \nFinancing plan, i.e., identified financing sources and details (e.g., \nproject financing, balance sheets, tax equity, sponsor equity), current status of any \nfinancing commitments or term sheets, and a general description of the capital \nstructure and expected timeline to financial close; \n \n(4) \nPermitting plan, e.g., a list of all applicable permits, current status, \nand timeline to obtain each; \n \n(5) \nSigned memorandum for the acquisition of major equipment, \ninvoices or agreements to acquire major equipment, or other documentary evidence \nthat major equipment has been procured; \n \n(6) \nEvidence of experience having constructed a previous project of \nsimilar size and technology or have contracted with an engineering, procurement, \nand construction partner with such experience, or contract with an engineering, \nprocurement, and construction partner with such experience; \n \n(7) \nFor natural gas-fueled generation resources, evidence of delivery \ninfrastructure arrangements in the form of a notice of intent or attestation of pipeline \ncapacity expansion to support the new project; and \n \n(8) \nFor generation and/or energy storage resources located outside of \nthe PJM Region, evidence of (a) a completed facilities study or equivalent under \nthe host Regional Transmission Organization/Independent System Operator’s or \nutility’s interconnection process and (b) long-term firm point-to-point transmission \nservice, or a confirmed transmission service request with a completed system \nimpact study, sufficient to deliver capacity to the border of the PJM Region \nconsistent with the requirements of Tariff, Attachment DD, section 5.5A(b)."},{"page":117,"startToken":45638,"endToken":45966,"text":"RBP Sell Offers for Demand Resources or DER Capacity Aggregation Resources must be \naccompanied by: \n \n(9) \nLocations within the PJM Region by Zone/Sub-zonal LDA and \naggregate capacity for RBP Sell Offers; \n \n(10) \nExecuted customer agreements or binding commitments covering \nthe proposed RBP UCAP MW commitment, with identified locations, customer \nnames, and expected curtailment/injection capability per site; and \n \n(11) \nEquipment procurement plan or evidence of deployed enabling \ninfrastructure such as metering, telemetry, load control, SCADA/dispatch systems, \nor DER major equipment as applicable. \n \nRBP Sell Offers for DER Capacity Aggregation Resources must also be accompanied by: \n \n(12) \nApplicable Electric Distributor interconnection/distribution impact \nstudy requirements and a plan to initiate on a timeline consistent with the proposed \ndelivery date.  \n \nRBP Sell Offers for Demand Resources must also be accompanied by: \n \n(13) \nElectric Distributor coordination requirements for metering, \ntelemetry, and baseline measurement infrastructure. \n \n(ii) \nStage 2: Selection Assessment \n \nAll RBP Sell Offers that pass the gating criteria evaluation shall be evaluated based on the \nfirst Delivery Year offered in the RBP Sell Offer, levelized cost, and RBP UCAP MW \nquantity.   \n \nRBP Sell Offers shall be selected in rank order from earliest to latest offered Delivery Year, \nand then in least-cost order based on the levelized cost ($/MW-day) of UCAP MW over \nthe fixed 15-year term, until the Final RBP Target is satisfied for any Delivery Year up \nthrough the 2032/2033 Delivery Year.  RBP Resources shall not be partially cleared.  In \nselecting the least-cost solution that satisfies the Final RBP Target and the cost of \nprocurement constraint, the Office of the Interconnection may commit an RBP Sell Offer \nwith an offered quantity that exceeds the remaining Final RBP Target to the extent such \nsolution provides greater economic efficiency than an alternative solution that satisfies the \nrequirements and constraints. \n \nThe levelized cost of each RBP Sell Offer shall be calculated as: \n \nLevelized Cost ($/MW-day) = Net Present Value (RBP Sell Offer price x UCAP \noffered)/Net Present Value (UCAP offered)"},{"page":118,"startToken":45966,"endToken":46368,"text":"with a discount rate equal to 9.5% after-tax average weighted average cost of capital \n(ATWACC). \n \nThe MW-weighted average of the levelized procurement cost of all selected RBP Sell \nOffers shall not exceed $555/MW-day UCAP. \n \nIn the event that two or more RBP Sell Offers with the same initial offered Delivery Year \nand levelized cost, and fewer than all of such offers are needed to satisfy the Final RBP \nTarget, the Office of the Interconnection shall select the RBP Sell Offer(s) proposing \nresources based on the earliest timestamp of such RBP Sell Offer(s). \n \nIn the event that the Reliability Backstop Procurement cannot meet the Final RBP Target, \nthe Reliability Backstop Procurement shall clear short of the Final RBP Target.   \n \n(g) \nSettlement Structure \n \n(i) \nUCAP MW Eligible to Be Settled as Contract for Difference \n \n \nEach RBP Resource that has been committed in the Reliability Backstop Procurement shall \nbe individually settled as a contract for difference (“CfD”).   \n \nAn RBP Resource’s total daily MW eligible to be settled as a CfD shall be the lesser of the \nRBP Resource’s daily committed RBP UCAP MW, daily owned UCAP MW, and daily \ncleared RPM UCAP MW.  \n \nAll UCAP MW of an RBP Resource above the committed RBP UCAP MW shall be \neligible to participate in RPM Auctions, subject to existing RPM rules, without being \nsubject to RBP obligations or settlement. \n \n(ii) \nRBP Settlement Credits Based on Contract for Difference  \n \nAn RBP Resource’s contract for difference (“CfD”), represented as positive or negative \nRBP Settlement Credits, shall be settled daily as the product of the total daily UCAP MW \neligible to settle as CfD and the difference between the price at which the RBP Resource \nwas committed in the Reliability Backstop Procurement for a Delivery Year and the RBP \nResource’s unit-specific weighted average resource clearing price of all applicable RPM \nAuctions from the associated Delivery Year.  Applicable RPM Auctions include all RPM \nAuctions for the associated Delivery Year that are conducted after the Reliability Backstop \nProcurement.  If the RBP Resource is committed through the RBP for a Delivery Year in \nwhich PJM has already conducted the Base Residual Auction, the CfD will be settled using \nthe difference between the price at which the RBP Resource was committed in the \nReliability Backstop Procurement for such Delivery Year and the weighted average \nresource clearing price in the applicable Incremental Auction(s) for such Delivery Year. \n \n(iii) \nRBP Charges"},{"page":119,"startToken":46368,"endToken":46425,"text":"RBP Charges shall be based on the total RBP Settlement Credits, positive and negative, of \nall RBP Resources across the PJM Region.   \n \nRBP Charges shall be calculated daily and allocated to Load Serving Entities by the \nrelevant Electric Distributor(s) in accordance with Tariff, Attachment DD, section 18.3(b) \nand the RAA, Article 7, section 2B."},{"page":120,"startToken":46425,"endToken":46849,"text":"18.6 \nRBP Resource Obligations  \n(a) \nCapacity Must Offer Obligation  \n \nAn RBP Resource committed through the Reliability Backstop Procurement must offer all \ncommitted RBP UCAP MW into the RPM Auctions as Capacity Resources pursuant to the \ncapacity must offer requirements and exceptions set forth in Tariff, Attachment DD, sections 6.6 \nand 6.6A. The applicable RPM auctions shall be the Base Residual Auctions and Incremental \nAuctions conducted after an RBP Resource’s RBP UCAP MW have been committed through the \nReliability Backstop Procurement and continuing for each subsequent Delivery Year through the \nend of the fixed 15-year term, except RBP UCAP MW for RBP Resources without a notice of \nintent to offer submitted pursuant to Tariff, Attachment DD, section 5.5 for the 2029/2030 Base \nResidual Auction shall have a must offer requirement in the next RPM Auction, including but not \nlimited to the 2030/2031 Base Residual Auction and the 2029/2030 Second Incremental Auction.  \nThe RBP Resource’s capacity must offer obligation into RPM Auctions for a Delivery Year is \nsatisfied once the entirety of the committed RBP UCAP MW have cleared in RPM Auction(s) for \nsuch Delivery Year.    \n \nRBP Resources with RBP UCAP MW committed through RPM Auctions will be subject to all \nRPM capacity market rules, as set forth in Tariff, Attachments DD and DD-1.  \n \n(i) \nPrice  \n \nRBP UCAP MW committed through the Reliability Backstop Procurement, and not \nqualifying for an exception pursuant to Tariff, Attachment DD, section 6.6(g), must be \noffered into the applicable RPM Auctions as price takers, i.e., $0/MW-day UCAP.  \n \n(ii) \nQuantity \n \nRBP Resources committed through the Reliability Backstop Procurement must be offered \ninto the applicable RPM Auctions.  The UCAP MW quantity offered in an applicable RPM \nAuction for the Delivery Year must be a quantity equal to the lesser of committed RBP \nUCAP MW minus total RPM committed MW through RPM Auctions for the Delivery \nYear and the available UCAP MW at the time of the RPM Auction.   \n \n(b) \nExceptions to the Must Offer Obligation \n \nAn RBP Resource that is granted an exception to the RPM must-offer obligation, as set forth in \nTariff, Attachment DD, section 6.6(g) or 6.6A(c), shall nevertheless be subject to the RBP shortfall \ncharge.   \n \n(c) \nRBP Shortfall UCAP MW \n \nRBP UCAP MW committed through the Reliability Backstop Procurement that is unable to be \ndelivered in a Delivery Year within the fixed, 15-year period will not be compensated for the \nundelivered megawatts via RBP Settlement Credits for each day the daily unforced capacity value"},{"page":121,"startToken":46849,"endToken":47190,"text":"of the RBP Resource is below the daily committed RBP UCAP MW and will be subject to any \napplicable RBP shortfall charges. \n \n(d) \nRBP Shortfall Charges  \n \nRBP Resources with RBP UCAP MW committed through the Reliability Backstop Procurement \nthat are unable to meet its full RBP UCAP MW commitment due to not achieving commercial \noperation by the first Delivery Year of the RBP commitment shall be subject to RBP shortfall \ncharges for the committed RBP UCAP MW until the resources achieves commercial operation, \nfor up to three years.   \n \nRBP shortfall charges shall be assessed daily, beginning in the first Delivery Year of the RBP \ncommitment, on the full RBP committed UCAP.  \n \nThe RBP shortfall charge shall equal the committed RBP UCAP MW times a charge rate equal to \n20% of the RBP commitment price of such resource (i.e., RBP shortfall charge = committed RBP \nUCAP MW * 20% of RBP commitment price), for the applicable Delivery Year \n \n(i) \nException to RBP Shortfall Charges \n \nAn RBP Resource that is a generation or Energy Storage Resource and is unable to meet \nexpected commercial operation date solely due to Network Upgrades shall be excepted \nfrom RBP shortfall charges if the RBP Resource successfully demonstrates readiness \nthrough test energy and seeks interim deliverability. \n \n(e) \nFailure of RBP UCAP MW to Materialize \n \nCommitments of RBP UCAP MW through the Reliability Backstop Procurement shall be \nrescinded for the remainder of the fifteen-year term where RBP UCAP MW fail to come online \nfor three Delivery Years beginning with the first Delivery Year in which the RBP Resource was \ncommitted.  Once rescinded, RBP UCAP MW commitments will not be eligible to be compensated \nas RBP UCAP MW for the remainder of the fixed 15-year term and shall no longer be subject to \nRBP shortfall charges.    \n \n(f) \nChange in Ownership \n \nCommitments of RBP UCAP MW shall follow the RBP Resource.  With change in ownership of \nthe RBP Resource, the commitment of RBP UCAP MW shall be conveyed to the new owner and \ncontinue through the end of the fixed 15-year term."},{"page":122,"startToken":47190,"endToken":47720,"text":"18.7 \nExiting Transmission Owner RBP Obligations \n \nIn the event a Transmission Owner exits PJM Interconnection, L.L.C. and the quantity of load with \nthe Transmission Owner is commensurate with the RBP Resources that are located in that \nTransmission Owner’s territory, the Transmission Owner shall honor the remaining term of the \nRBP commitment. \n \n(a) \nExiting Transmission Owner with Committed RBP Resources  \n \nAny Transmission Owner seeking to exit PJM Interconnection, L.L.C. may, prior to exiting PJM, \nenter into agreements that maintain appropriate rates, terms, and conditions that preserves the RBP \ncommitments with the owners of RBP Resource(s) that have been committed through the \nReliability Backstop Procurement that are located within the physical boundaries of the \nTransmission Owner’s Zone.  PJM and PJMSettlement shall be relieved of any applicable RBP \nobligations made to RBP Resources that are subject to such agreements. In the event no such \nagreement is made and such RBP Resource(s) can be pseudo-tied into the PJM Region, the exiting \nTransmission Owner must, to the extent the Office of the Interconnection elects to retain such RBP \nResource throughout the term of its RBP commitment, pay all costs for RBP Resources to pseudo-\ntie into the PJM Region so that such resource meets the external Capacity Resource eligibility \nrequirements set forth in Tariff, Attachment DD, section 5.5A prior to the Transmission Owner \nexiting PJM Interconnection, L.L.C. \n \nAny Transmission Owner seeking to exit PJM Interconnection, L.L.C. with RBP Resource(s) that \n(i) are located within the physical boundaries of the Transmission Owner’s Zone and (ii) cannot \nbe pseudo-tied into the PJM Region, and/or which the Office of the Interconnection elects not to \nretain the RBP Resource as a Capacity Resource throughout the term of its RBP commitment, shall \npay costs associated with the remaining term of the RBP Resource, the amount which shall be \ndetermined through a filing submitted under the Federal Power Act, prior to exiting PJM \nInterconnection, L.L.C.  Revenues collected in such an event shall be credited to Load Serving \nEntities that are allocated a share of the RBP Charges on a pro rata basis through the remaining \nterm of the RBP commitment. \n \n(b) \nExiting Transmission Owner with Load Allocated RBP Charges \n \nAny Transmission Owner seeking to exit PJM Interconnection, L.L.C. with net load that has been \nallocated RBP Charges for RBP Resources not located within the physical boundaries of the \nTransmission Owner’s Zone may, prior to exiting PJM, enter into agreements that maintain \nappropriate rates, terms and conditions that preserves the RBP commitments with the owners of \nsuch RBP Resource(s). PJM and PJMSettlement shall be relieved of any applicable RBP \nobligations made to RBP Resources that are subject to such agreements. In the event no such \nagreement is made, the exiting Transmission Owner must pay all forward obligations on an \naccelerated basis, the amount which shall be determined through a filing submitted under the \nFederal Power Act, prior to exiting PJM Interconnection, L.L.C.  Any such revenues collected \nshall be distributed to the RBP Resources under the standard daily RBP settlement schedule to \nsuch resources through the remaining term of the RBP commitment."},{"page":123,"startToken":47720,"endToken":48122,"text":"18.8 Credit Requirements for RBP Sellers and LSEs Allocated RBP Charges \n \nThe provisions of Tariff, Attachment DD, section 18.8(a) shall apply to RBP Sellers seeking to \nsubmit RBP Sell Offers in the Reliability Backstop Procurement.  The provisions of Tariff, \nAttachment DD, section 18.8(b) shall apply to LSEs allocated costs for RBP UCAP MW procured \nthrough the Reliability Backstop Procurement, as determined in accordance with Tariff, \nAttachment DD, section 18.3.  Nothing in this Tariff, Attachment DD, section 18 supersedes the \nprovisions of Tariff, Attachment Q.   \n \nIn addition, settlement during any Delivery Year of cleared positions resulting from, or expected \nto result from, the Reliability Backstop Procurement may be included, as appropriate, in Peak \nMarket Activity pursuant to Tariff, Attachment Q, Section VII.A.  The forms of acceptable credit \nsupport shall be limited to RBP Collateral. \n \nThe Reliability Backstop Procurement credit requirements described herein shall be separate from \nand additional to any credit requirements for participation in RPM Auctions and bilateral \ntransactions under Tariff, Attachment DD, section 4.6, and other market activity in the PJM \nMarkets, as set forth in Tariff, Attachment Q, and shall be applied separately to each RBP Seller \nwith RBP Sell Offer and each LSE allocated cost for RBP UCAP MW procured through the \nReliability Backstop Procurement, as determined in accordance with Tariff, Attachment DD, \nsection 18.3.   \n \n(a) \nRBP Credit Requirements of RBP Sellers Seeking to Submit RBP Sell Offers  \n \nPrior to or simultaneous with submitting RBP Sell Offers, RBP Sellers seeking to participate in \nthe Reliability Backstop Procurement must post the appropriate amount of the Reliability Backstop \nProcurement credit requirement to each RBP Resource for which RBP Sell Offers are submitted.   \n \n(i) \nApplicability \n \nAn RBP Seller seeking to submit an RBP Sell Offer in the Reliability Backstop \nProcurement must satisfy the credit requirement, i.e., the RBP credit requirement specified \nherein, prior to or simultaneously with submitting such RBP Sell Offer.   \n \n(ii) \nRBP Resource Credit Requirement  \n \nThe credit requirement applicable to an RBP Seller seeking to submit an RBP Sell Offer in \nthe Reliability Backstop Procurement shall be the RBP credit requirement as provided in \nTariff, Attachment DD, section 18.8(iv).  \n \nThe total RBP credit requirement for each RBP Seller shall be, for the sum of the credit \nrequirements for all RBP Sell Offers submitted by such RBP Seller in the Reliability \nBackstop Procurement.   \n \n(iii) \nReduction in RBP Credit Requirement"},{"page":124,"startToken":48122,"endToken":48469,"text":"(A) \nThe RBP credit requirement shall be returned for any RBP \nResources that do not receive a commitment through the Reliability Backstop \nProcurement, within five (5) business of the completion of the clearing process \npursuant to Tariff, Attachment DD, section 18.5(f).     \n \n(B) \nWhere an RBP Seller’s RBP Sell Offer is committed through the \nReliability Backstop Procurement and the RBP Resource subsequently achieves \ncommercial operation, the Office of the Interconnection may return the Reliability \nBackstop Procurement Credit Requirement after a one-year look-back from the \nachievement of commercial operation.    \n \n(iv) \nCalculation of RBP Credit Requirement for RBP Sellers Seeking to Submit \nRBP Sell Offers in the RBP  \n \nRBP Sell Offers submitted by RBP Sellers in the Reliability Backstop Procurement shall \nbe accompanied by a Reliability Backstop Procurement credit requirement, which shall be \nequal to:  \n \n3\n𝑛=1\n0.2 × (𝑅𝐵𝑃 𝑆𝑒𝑙𝑙 𝑂𝑓𝑓𝑒𝑟 𝑃𝑟𝑖𝑐𝑒 𝑖𝑛\n$\n𝑀𝑊𝑑𝑎𝑦) \n𝑛\n× (𝑈𝐶𝐴𝑃 𝑖𝑛 𝑀𝑊)𝑛× 365 \n𝑤ℎ𝑒𝑟𝑒 𝑛= 𝐷𝑒𝑙𝑖𝑣𝑒𝑟𝑦 𝑌𝑒𝑎𝑟 \n \n(v) \nCredit Responsibility for Traded RBP Resource Commitment \n \nThe Office of the Interconnection may require that credit and financial responsibility for a \ncommitted RBP Resource that is traded remain with the original party (which for these \npurposes, means the party bearing credit responsibility for the committed RBP Resource \nimmediately prior to trade) unless the Office of the Interconnection determines that the \nreceiving party has independently posted sufficient credit support with the Office of the \nInterconnection and agreed by providing written confirmation to the Office of the \nInterconnection that it will fully assume the credit responsibility associated with the \ncommitted RBP Resource.  In determining the appropriate level of credit for any receiving \nparty, the Office of the Interconnection may rely on Tariff, Attachment Q. \n \n(b) \nRBP Credit Requirements Applicable to Load Serving Entities Responsible for \nRBP Charges  \n \nPrior to the first Delivery Year, the assessment of an RBP credit requirement by the Office of the \nInterconnection, LSEs allocated cost responsibility for RBP Charges, pursuant to Tariff, \nAttachment DD, section 18.3, must post RBP Collateral for the RBP credit requirement, calculated \nas set forth herein: \n \n(i) \nRBP Credit Requirement for Load Serving Entities"},{"page":125,"startToken":48469,"endToken":48913,"text":"(A) \nThe cumulative RBP credit requirement for Load Serving Entities \nfor a given Delivery Year shall be equivalent to the product of the RBP Credit Rate \nmultiplied by RBP UCAP MW committed, where  \n \nthe RBP Credit Rate shall equal $1.5 million, as may be reduced, for \nreasons including a change in the total committed RBP UCAP MW, when \ntotal posted RBP Collateral is greater than the total remaining RBP Charges \nobligations, over time by the Office of the Interconnection to an amount \nsufficient to cover the total existing RBP Charges obligations; and   \n \nthe RBP UCAP MW committed amount shall equal the amount of \nRBP UCAP MW that receives a commitment through the Reliability \nBackstop Procurement minus each commitment of RBP UCAP MW that is \nrescinded pursuant to Tariff, Attachment DD, section 18.6(e).   \n \nThe cumulative RBP credit requirement shall be met through RBP Collateral posted \nby those Load Serving Entities allocated cost pursuant to Tariff, Attachment DD, \nsection 18.3. \n \n(B) \nThe Office of the Interconnection shall apply the following credit \nrequirements to each Load Serving Entity allocated responsibility for RBP \nObligations, pursuant to Tariff, Attachment DD, section 18.3, as follows: \n \n(1) \nFor Load Serving Entities with an RBP Obligation in \naccordance Tariff, Attachment DD, section 18.3, prior to forty-five (45) \ndays before the start of the Delivery Year, such Load Serving Entities, must \npost, or maintain an existing, RBP Collateral equal to $1.5 million x the \nallocated RBP Obligation MW, where the RBP Obligation MW equals the \nRBP Obligation MW submitted for the Load Serving Entity by the Electric \nDistributor and scaled, as necessary, in the event that the RBP Obligation \nMW values uploaded by the Electric Distributor do not sum to the fixed, \nFinal RBP Target MW for the zone/area.  For Load Serving Entities \nrequired to post RBP Collateral by the foregoing sentence, the Office of the \nInterconnection may evaluate such Load Serving Entity for unreasonable \ncredit risk under the Unreasonable Credit Risk provisions of Tariff, \nAttachment Q, Section II, and require additional RBP Collateral as \nappropriate.   \n \n(2) \nTo the extent such Load Serving Entity is allocated cost \npursuant to Tariff, Attachment DD, section 18.3 and no RBP Obligations \nare reported to the Office of the Interconnection in an Electric Distributor \nzone/area in which the Load Serving Entity serves load, prior to forty-five \n(45) days before the start of the Delivery Year, such Load Serving Entities, \nmay be required to post, or maintain an existing, RBP Collateral equal to \nthe product of the RBP Credit Rate multiplied by the allocated RBP UCAP \nMW, where the allocated RBP UCAP MW shall equal the Load Serving"},{"page":126,"startToken":48913,"endToken":49153,"text":"Entity’s pro-rata share of the Daily Unforced Capacity Obligation for the \nzone/area as determined in RAA, Schedule 8.  For Load Serving Entities \nrequired to post RBP Collateral by the foregoing sentence, the Office of the \nInterconnection may evaluate whether such Load Serving Entity for \nunreasonable credit risk under the Unreasonable Credit Risk provisions of \nTariff, Attachment Q, Section II, and require additional RBP Collateral as \nappropriate. \n \n(C) \nCredit Requirements Associated With Intra-Delivery Year Transfer \nof Load and Allocated RBP UCAP MW Cost Responsibility  \n \n(1) \nTo the extent a Load Serving Entity transfers its load serving \nobligations that are associated with RBP UCAP MW, as determined \npursuant to Tariff, Attachment DD, section 18.3, then the transferee LSE \nmust fully satisfy all applicable credit and collateral requirements required \nherein associated with such transferred RBP UCAP MW obligation and, as \napplicable, the credit requirements in Tariff, Attachment Q.  Transferee \nshall independently post sufficient RBP Collateral directly with the Office \nof the Interconnection to satisfy the incremental RBP UCAP MW \nassociated with the acquired load. \n \n(2) \nTransferor shall be released from its financial obligations for \namount of RBP Collateral associated with the RBP UCAP MW associated \nwith the transferred load.  Any RBP Collateral posted by transferor shall be \nreturned once Transferee has posted the RBP Collateral determined in \naccordance with Tariff, Attachment DD, section 18.8(c) and any unpaid \ninvoice amounts associated with such transfer have been paid by the \ntransferor."},{"page":127,"startToken":49153,"endToken":49284,"text":"18.9 \nRBP Default Allocation \n \n(a) \nLSE Nonpayment of RBP Charges \nIn the event a Load Serving Entity defaults and fails to pay an RBP Charge, the defaulted amount \nwill be allocated to all remaining Load Serving Entities responsible for paying RBP Charges based \non their pro-rata share of the total RBP Charges for all such Load Serving Entities. Such amounts \nmay be offset by the RBP Collateral posted by the defaulting Load Serving Entity. \n \n(b) \nRBP Resource Nonpayment of RBP Shortfall Charges \n \nIn the event that an RBP Resource subject to RBP shortfall charges pursuant to Tariff, Attachment \nDD, section 18.6(d) defaults on payment of RBP shortfall charges, the corresponding credits will \nnot be allocated to the Load Serving Entities that would otherwise receive the RBP shortfall credits."},{"page":128,"startToken":49284,"endToken":49696,"text":"ARTICLE 1 – DEFINITIONS \n \n \nUnless the context otherwise specifies or requires, capitalized terms used herein shall \nhave the respective meanings assigned herein or in the Schedules hereto, or in the PJM Tariff or \nPJM Operating Agreement if not otherwise defined in this Agreement, for all purposes of this \nAgreement (such definitions to be equally applicable to both the singular and the plural forms of \nthe terms defined).  Unless otherwise specified, all references herein to Articles, Sections or \nSchedules, are to Articles, Sections or Schedules of this Agreement. As used in this Agreement: \n \n \nAccredited UCAP: \n \n“Accredited UCAP” shall mean the quantity of Unforced Capacity, as denominated in Effective \nUCAP, that an ELCC Resource is capable of providing in a given Delivery Year. \n \nAccredited UCAP Factor: \n \n“Accredited UCAP Factor” shall mean, through the 2024/2025 Delivery Year, one minus \nEFORd, and for 2025/2026 Delivery Year and subsequent Delivery Years, the ratio of the \nCapacity Resource’s Accredited UCAP to the Capacity Resource’s installed capacity. \n \nAgreement: \n \n \n“Agreement” shall mean this Reliability Assurance Agreement, together with all Schedules \nhereto, as amended from time to time. \n \nAnnual Demand Resource: \n \n“Annual Demand Resource” shall mean a resource that is placed under the direction of the \nOffice of the Interconnection  during the Delivery Year, and will be available for an unlimited \nnumber of interruptions during such Delivery Year by the Office of the Interconnection, and will \nbe capable of maintaining each such interruption between the hours of 10:00AM to 10:00PM \nEastern Prevailing Time for the months of June through October and the following May, and \n6:00AM through 9:00PM Eastern Prevailing Time for the months of November through April \nunless there is an Office of the Interconnection approved maintenance outage during October \nthrough April.  The Annual Demand Resource must be available in the corresponding Delivery \nyear to be offered for sale or Self-Supplied in an RPM Auction, or included as an Annual \nDemand Resource in an FRR Capacity Plan for the corresponding Delivery Year. \n \nAnnual Energy Efficiency Resource: \n \n“Annual Energy Efficiency Resource” shall mean a project, including installation of more \nefficient devices or equipment or implementation of more efficient processes or systems, \nmeeting the requirements of  Reliability Assurance Agreement, Schedule 6 and exceeding then-\ncurrent building codes, appliance standards, or other relevant standards, designed to achieve a \ncontinuous (during the summer and winter periods described in such Schedule 6 and the PJM \nManuals) reduction in electric energy consumption that is not reflected in the peak load forecast"},{"page":129,"startToken":49696,"endToken":50091,"text":"prepared for the Delivery Year for which the Energy Efficiency Resource is proposed, and that is \nfully implemented at all times during such Delivery Year, without any requirement of notice, \ndispatch, or operator intervention. \n \nApplicable Regional Entity: \n \n \n“Applicable Regional Entity” shall have the same meaning as in the PJM Tariff.   \n \nBase Capacity Demand Resource: \n \n“Base Capacity Demand Resource” shall mean, for the 2018/2019 and 2019/2020 Delivery \nYears, a resource that is placed under the direction of the Office of the Interconnection and that \nwill be available June through September of a Delivery Year, and will be available to the Office \nof the Interconnection for an unlimited number of interruptions during such months, and will be \ncapable of maintaining each such interruption for at least a 10-hour duration between the hours \nof 10:00AM to 10:00PM Eastern Prevailing Time.  The Base Capacity Demand Resource must \nbe available June through September in the corresponding Delivery Year to be offered for sale or \nself-supplied in an RPM Auction, or included as a Base Capacity Demand Resource in an FRR \nCapacity Plan for the corresponding Delivery Year.   \n \nBase Capacity Energy Efficiency Resource:  \n \n“Base Capacity Energy Efficiency Resource” shall mean, for the 2018/2019 and 2019/2020 \nDelivery Years, a project, including installation of more efficient devices or equipment or \nimplementation of more efficient processes or systems, meeting the requirements of RAA, \nSchedule 6 and exceeding then-current building codes, appliance standards, or other relevant \nstandards, designed to achieve a continuous (during the summer peak periods as described in \nReliability Assurance Agreement, Schedule 6 and the PJM Manuals) reduction in electric energy \nconsumption that is not reflected in the peak load forecast prepared for the Delivery Year for \nwhich the Base Capacity Energy Efficiency Resource is proposed, and that is fully implemented \nat all times during such Delivery Year, without any requirement of notice, dispatch, or operator \nintervention. \n \nBase Capacity Resource:  \n \n“Base Capacity Resource” shall have the same meaning as in Tariff, Attachment DD. \n \nBase Residual Auction: \n \n \n“Base Residual Auction” shall have the same meaning as in Tariff, Attachment DD. \n \n \nBehind The Meter Generation: \n \n \n“Behind The Meter Generation” shall refer to a generating unit that delivers energy to load \nwithout using the Transmission System or any distribution facilities (unless the entity that owns \nor leases the distribution facilities consented to such use of the distribution facilities and such"},{"page":130,"startToken":50091,"endToken":50578,"text":"consent has been demonstrated to the satisfaction of the Office of the Interconnection; provided, \nhowever, that Behind The Meter Generation does not include (i) at any time, any portion of such \ngenerating unit’s capacity that is designated as a Generation Capacity Resource or DER Capacity \nAggregation Resource or (ii) in any hour, any portion of the output of such generating unit that is \nsold to another entity for consumption at another electrical location or into the PJM Interchange \nEnergy Market. \n \n \nBlack Start Capability: \n \n \n“Black Start Capability” shall mean the ability of a generating unit or station to go from a \nshutdown condition to an operating condition and start delivering power without assistance from \nthe power system. \n \n \nCapacity Emergency Transfer Objective (CETO): \n \n \n“Capacity Emergency Transfer Objective” or “CETO” shall mean, through the 2024/2025 \nDelivery Year, the amount of electric energy that a given area must be able to import in order to \nremain within a loss of load expectation of one event in 25 years when the area is experiencing a \nlocalized capacity emergency, as determined in accordance with the PJM Manuals.  Without \nlimiting the foregoing, CETO shall be, for Delivery Years through 2024/2025, calculated based \nin part on EFORD determined in accordance with Reliability Assurance Agreement, Schedule 5, \nParagraph C. Beginning with the 2025/2026 Delivery Year, CETO shall mean the amount of \nelectric energy that a given area must be able to import in order to satisfy a normalized expected \nunserved energy for the area that is equal to forty percent of the normalized expected unserved \nenergy for the RTO when at the annual reliability criteria, where normalized expected unserved \nenergy is the expected unserved energy (for the area or RTO, as appropriate) divided by  the \nforecasted annual energy (for the area or RTO, as appropriate), when the area is experiencing a \nlocalized capacity emergency, as determined in accordance with the PJM Manuals. \n \n \nCapacity Emergency Transfer Limit (CETL): \n \n \nCapacity Emergency Transfer Limit” or “CETL” shall mean the capability of the transmission \nsystem to support deliveries of electric energy to a given area experiencing a localized capacity \nemergency as determined in accordance with the PJM Manuals. \n \n \nCapacity Import Limit: \n \nFor any Delivery Year up to and including the 2019/2020 Delivery Year, “Capacity Import \nLimit” shall mean, (a) for the PJM Region, (1) the maximum megawatt quantity of external \nGeneration Capacity Resources that PJM determines for each Delivery Year, through appropriate \nmodeling and the application of engineering judgment, the transmission system can receive, in \naggregate at the interface of the PJM Region with all external balancing authority areas and \ndeliver to load in the PJM Region under capacity emergency conditions without violating \napplicable reliability criteria on any bulk electric system facility of 100kV or greater, internal or \nexternal to the PJM Region, that has an electrically significant response to transfers on such \ninterface, minus (2) the then-applicable Capacity Benefit Margin; and (b) for certain source"},{"page":131,"startToken":50578,"endToken":51192,"text":"zones identified in the PJM manuals as groupings of one or more balancing authority areas, (1) \nthe maximum megawatt quantity of external Generation Capacity Resources that PJM \ndetermines the transmission system can receive at the interface of the PJM Region with each \nsuch source zone and deliver to load in the PJM Region under capacity emergency conditions \nwithout violating applicable reliability criteria on any bulk electric system facility of 100kV or \ngreater, internal or external to the PJM Region, that has an electrically significant response to \ntransfers on such interface, minus the then-applicable Capacity Benefit Margin times (2) the ratio \nof the maximum import quantity from each such source zone divided by the PJM total maximum \nimport quantity.  As more fully set forth in the PJM Manuals, PJM shall make such \ndetermination based on the latest peak load forecast for the studied period, the same computer \nsimulation model of loads, generation and transmission topography employed in the \ndetermination of Capacity Emergency Transfer Limit for such Delivery Year, including external \nfacilities from an industry standard model of the loads, generation, and transmission topography \nof the Eastern Interconnection under peak conditions.  PJM shall specify in the PJM Manuals the \nareas and minimum distribution factors for identifying monitored bulk electric system facilities \nthat have an electrically significant response to such transfers on the PJM interface.  Employing \nsuch tools, PJM shall model increased power transfers from external areas into PJM to determine \nthe transfer level at which one or more reliability criteria is violated on any monitored bulk \nelectric system facilities that have an electrically significant response to such transfers.  For the \nPJM Region Capacity Import Limit, PJM shall optimize transfers from other source areas not \nexperiencing any reliability criteria violations as appropriate to increase the Capacity Import \nLimit.  The aggregate megawatt quantity of transfers into PJM at the point where any increase in \ntransfers on the interface would violate reliability criteria will establish the Capacity Import \nLimit.  Notwithstanding the foregoing, a Capacity Resource located outside the PJM Region \nshall not be subject to the Capacity Import Limit if the Capacity Market Seller seeks an \nexception thereto by demonstrating to PJM, by no later than five (5) business days prior to the \ncommencement of the offer period for the relevant RPM Auction, that such resource meets all of \nthe following requirements: \n(i)  \nit has, at the time such exception is requested, met all applicable requirements to \nbe pseudo-tied into the PJM Region, or the Capacity Market Seller has committed in writing that \nit will meet such requirements, unless prevented from doing so by circumstances beyond the \ncontrol of the Capacity Market Seller, prior to the relevant Delivery Year; \n \n(ii)  \nat the time such exception is requested, it has long-term firm transmission service \nconfirmed on the complete transmission path from such resource into PJM; and \n \n(iii) \nit is, by written commitment of the Capacity Market Seller, subject to the same \nobligations imposed on Generation Capacity Resources located in the PJM Region by Tariff, \nAttachment DD, section 6.6 to offer their capacity into RPM Auctions; provided, however, that \n(a) the total megawatt quantity of all exceptions granted hereunder for a Delivery Year, plus the \nCapacity Import Limit for the applicable interface determined for such Delivery Year, may not \nexceed the total megawatt quantity of Network External Designated Transmission Service on \nsuch interface that PJM has confirmed for such Delivery Year; and (b) if granting a qualified \nexception would result in a violation of the rule in clause (a), PJM shall grant the requested \nexception but reduce the Capacity Import Limit by the quantity necessary to ensure that the total \nquantity of Network External Designated Transmission Service is not exceeded."},{"page":132,"startToken":51192,"endToken":51594,"text":"Capacity Only Option: \n \n“Capacity Only Option” shall mean participation in Emergency Load Response Program or Pre-\nEmergency Program which allows, pursuant to Tariff, Attachment DD and as applicable, a \ncapacity payment for the ability to reduce load during a pre-emergency or emergency event. \n \nCapacity Performance Resource: \n \n“Capacity Performance Resource” shall have the same meaning as in Tariff, Attachment DD. \n \nCapacity Resources: \n \n \n“Capacity Resources” shall mean megawatts of (i) net capacity from Existing Generation \nCapacity Resources or Planned Generation Capacity Resources meeting the requirements of the \nReliability Assurance Agreement, Schedules 9 and Reliability Assurance Agreement, Schedule \n10 that are or will be owned by or contracted to a Party and that are or will be committed to \nsatisfy that Party's obligations under the Reliability Assurance Agreement, or to satisfy the \nreliability requirements of the PJM Region, for a Delivery Year; (ii) net capacity from Existing \nGeneration Capacity Resources or Planned Generation Capacity Resources not owned or \ncontracted for by a Party which are accredited to the PJM Region pursuant to the procedures set \nforth in such Schedules 9 and 10; or (iii)  load reduction capability provided by Demand \nResources or Energy Efficiency Resources that are accredited to the PJM Region pursuant to the \nprocedures set forth in the Reliability Assurance Agreement, Schedule 6; or (iv) generation and \nload reduction capability provided by a DER Capacity Aggregation Resource, pursuant to the \nprocedures set forth in the Reliability Assurance Agreement, Schedule 6.2 and the PJM Manuals. \n \n \nCapacity Resource Provider: \n \n“Capacity Resource Provider” shall mean a Member that (1) owns, or has the contractual \nauthority to control the output of, a Generation Capacity Resource, that has not transferred such \nauthority to another entity; (2) or a DER Aggregator that has a contractual relationship to use a \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource. \n \nCapacity Storage Resource Class: \n \n“Capacity Storage Resource Class” shall mean the ELCC Classes specified in Schedules 9.1 and \n9.2, section B of this Agreement, each of which is composed of (1) Capacity Storage Resources \nwith the same specified characteristic duration of 4, 6, 8, and 10 hours or; (2) storage device \nComponent DER. The characteristic duration of an Energy Storage Resource Class is the ratio of \nthe modeled MWh energy storage capability of members of the class to the modeled MW power \ncapability of members of the class. \n \nCapacity Transfer Right:"},{"page":133,"startToken":51594,"endToken":51911,"text":"“Capacity Transfer Right” shall have the meaning specified in Tariff, Attachment DD. \n \nCoal Class: \n \n \n“Coal Class” shall mean an ELCC Class consisting of Unlimited Resources primarily \nfueled by coal. \n \nCombination Resource: \n \n“Combination Resource” shall mean a Generation Capacity Resource, or a generation \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource, that has a component that has the characteristics of a Limited Duration \nResource combined with (i) a component that has the characteristics of an Unlimited Resource or \n(ii) a component that has the characteristics of a Variable Resource. \n \nCompliance Aggregation Area (CAA): \n \n“Compliance Aggregation Area” or “CAA” shall have the same meaning as in the Tariff. \n \nComplex Hybrid Class: \n \n“Complex Hybrid Class” shall mean an ELCC Class composed of Combination Resources that \ncombine three or more components, whereby one component is a class of Limited Duration \nResource, and the other components are different Variable Resource classes, and such \nCombination Resources cannot be included in any other Combination Resource class. A resource \nthat is a member of a Complex Hybrid Class has a single Point Of Interconnection, unless the \nresource is controlled in an integrated fashion, is at a single site, and is approved by PJM to be \nconsidered a single resource in accordance with the PJM Manuals. \n \nConsolidated Transmission Owners Agreement, PJM Transmission Owners Agreement or \nTransmission Owners Agreement: \n \n \n“Consolidated Transmission Owners Agreement,” “PJM Transmission Owners Agreement” or \n“Transmission Owners Agreement” shall mean that certain Consolidated Transmission Owners \nAgreement, dated as of December 15, 2005, by and among the Transmission Owners and by and \nbetween the Transmission Owners and PJM Interconnection, L.L.C. on file with the \nCommission, as amended from time to time. \n \n \nControl Area: \n \n“Control Area” shall mean an electric power system or combination of electric power systems \nbounded by interconnection metering and telemetry to which a common generation control \nscheme is applied in order to:"},{"page":134,"startToken":51911,"endToken":52230,"text":"(a) \nmatch the power output of the generators within the electric power system(s) and \nenergy purchased from entities outside the electric power system(s), with the load within the \nelectric power system(s); \n \n \n \n(b) \nmaintain scheduled interchange with other Control Areas, within the limits of \nGood Utility Practice; \n \n \n \n (c) \nmaintain the frequency of the electric power system(s) within reasonable limits in \naccordance with Good Utility Practice and the criteria of NERC and each Applicable Regional \nEntity; \n \n \n \n(d) \nmaintain power flows on transmission facilities within appropriate limits to \npreserve reliability; and \n \n \n \n(e) \nprovide sufficient generating capacity to maintain operating reserves in \naccordance with Good Utility Practice. \n \n \nDaily Unforced Capacity Obligation: \n \n \n“Daily Unforced Capacity Obligation” shall mean the capacity obligation of a Load Serving \nEntity during the Delivery Year, determined in accordance with the Reliability Assurance \nAgreement, Schedule 8 or, as to an FRR Entity, in the Reliability Assurance Agreement, \nSchedule 8.1. \n \n \nDelivery Year: \n \n \n“Delivery Year” shall mean a Planning Period for which a Capacity Resource is committed \npursuant to the auction procedures specified in Tariff, Attachment DD or pursuant to an FRR \nCapacity Plan under RAA, Schedule 8.1. \n \n \nDemand Resource (DR): \n \n \n“Demand Resource” or “DR” shall mean a Limited Demand Resource, Extended Summer \nDemand Resource, Annual Demand Resource, Base Capacity Demand Resource or Summer-\nPeriod Demand Resource with a demonstrated capability to provide a reduction in demand or \notherwise control load in accordance with the requirements of RAA, Schedule 6 that offers and \nthat clears load reduction capability in a Base Residual Auction or Incremental Auction or that is \ncommitted through an FRR Capacity Plan.   \n \nDemand Resource Factor or DR Factor: \n \n \n“Demand Resource Factor” or “DR Factor” shall mean, for Delivery Years through May 31, \n2018, that factor approved from time to time by the PJM Board used to determine the unforced \ncapacity value of a Demand Resource in accordance with Reliability Assurance Agreement, \nSchedule 6"},{"page":135,"startToken":52230,"endToken":52566,"text":"Demand Resource Officer Certification Form: \n \n“Demand Resource Officer Certification Form” shall mean a certification as to an intended \nDemand Resource Sell Offer, in accordance with Reliability Assurance Agreement, Schedule 6 \nand Reliability Assurance Agreement, Schedule 8.1 and the PJM Manuals. \n \n \nDemand Resource Registration: \n \n“Demand Resource Registration” shall mean a registration in the Full Program Option or \nCapacity Only Option of the Emergency or Pre-Emergency Load Resource Program in \naccordance with Tariff, Attachment K-Appendix, section 8. \n \nDemand Resource Sell Offer Plan: \n \n“Demand Resource Sell Offer Plan” shall mean the plan required by Reliability Assurance \nAgreement, Schedule 6 and Reliability Assurance Agreement, Schedule 8.1 in support of an \nintended offer of Demand Resources in an RPM Auction, or an intended inclusion of Demand \nResources in an FRR Capacity Plan. \n \nDiesel Utility Class: \n \n\"Diesel Utility Class\" shall mean an ELCC Class consisting of Unlimited Resources of the diesel \ntechnology type that is not primarily fueled by landfill gas. \n \nDER Aggregator Officer Certification Form:  \n \n“DER Aggregator Officer Certification Form” shall mean a DER Aggregator’s certification as to \nan intended DER Capacity Aggregation Resource Sell Offer, in accordance with Reliability \nAssurance Agreement, Schedule 6.2 and Reliability Assurance Agreement, Schedule 8.1 and the \nPJM Manuals. \n \nDER Capacity Aggregation Resource Sell Offer Plan:  \n \n“DER Capacity Aggregation Resource Sell Offer Plan” shall mean the plan required by \nReliability Assurance Agreement, Schedule 6.2 and Reliability Assurance Agreement, Schedule \n8.1 in support of an intended offer of a DER Capacity Aggregation Resource in an RPM \nAuction, or an intended inclusion of a DER Capacity Aggregation Resource in an FRR Capacity \nPlan. \n \nEffective Nameplate Capacity: \n \n“Effective Nameplate Capacity” shall mean (i) for each Variable Resource and Combination \nResource that is a Generation Capacity Resource, the resource’s Maximum Facility Output (or, \nfor a Co-Located Resource, the applicable share of the Mixed Technology Facility’s Maximum \nFacility Output); (ii) for each Variable Resource and Combination Resource, that is an individual \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity"},{"page":136,"startToken":52566,"endToken":52970,"text":"Aggregation Resource, the device’s maximum energy production capability, as defined by the \nresource’s state interconnection agreement; or (iii) for each Limited Duration Resource, the \nsustained level of output that the device can provide and maintain over a continuous period, \nwhereby the duration of that continuous period matches the characteristic duration of the \ncorresponding ELCC Class, with consideration given to ambient conditions expected to exist at \nthe time of PJM system peak load, to the extent that such conditions impact such resource’s \ncapability, not to exceed the Maximum Facility Output (or, for a Co-Located Resource, the \napplicable share of the Mixed Technology Facility’s Maximum Facility Output).  For the \n2025/2026 Delivery Year and subsequent Delivery Years, the Effective Nameplate Capacity of \neach Limited Duration Resource shall not exceed the greater of the Capacity Interconnection \nRights of such Limited Duration Resource, or the transitional system capability as limited by the \ntransitional resource MW ceiling as defined in the PJM Manuals, awarded for the applicable \nDelivery Year. \n \nEffective UCAP: \n \n“Effective UCAP” shall mean a unit of measure that represents the capacity product transacted in \nthe Reliability Pricing Model and included in FRR Capacity Plans.  One megawatt of Effective \nUCAP has the same capacity value of one megawatt of Unforced Capacity. \n \nELCC Class: \n \n“ELCC Class” shall mean a defined group of ELCC Resources that share a common set of \noperational characteristics and for which effective load carrying capability analysis, as set forth \nin RAA, Schedules 9.1 and 9.2, will establish a unique ELCC Class UCAP and corresponding \nELCC Class Rating(s). ELCC Classes shall be defined in the Schedules 9.1 and 9.2, section B of \nthis Agreement.  Members of an ELCC Class shall share a common method of calculating the \nELCC Resource Performance Adjustment, provided that the individual ELCC Resource \nPerformance Adjustment values will generally differ among ELCC Resources. \n \nELCC Class Rating: \n \n“ELCC Class Rating” shall mean the rating factor, based on effective load carrying capability \nanalysis, that applies to ELCC Resources that are members of an ELCC Class as part of the \ncalculation of their Accredited UCAP. \n \nELCC Class UCAP: \n \n“ELCC Class UCAP” shall mean the aggregate Effective UCAP all modeled ELCC Resources in \na given ELCC Class are capable of providing in a given Delivery Year.  \n \nELCC Portfolio UCAP: \n \n“ELCC Portfolio UCAP” shall mean the aggregate Effective UCAP that all modeled ELCC \nResources are capable of providing in a given Delivery Year."},{"page":137,"startToken":52970,"endToken":53371,"text":"ELCC Resource: \n \n“ELCC Resource” shall mean a Component DER within a DER Aggregation Resource that is \nlinked to a DER Capacity Aggregation Resource, a Generation Capacity Resource or a Demand \nResource. \n \nELCC Resource Performance Adjustment: \n \n“ELCC Resource Performance Adjustment” shall mean the performance of a specific ELCC \nResource relative to the aggregate performance of the ELCC Class to which it belongs as further \ndescribed in RAA, Schedule 9.1, section F and RAA, Schedule 9.2, section D. \n \nElectric Cooperative: \n \n \n“Electric Cooperative” shall mean an entity owned in cooperative form by its customers that is \nengaged in the generation, transmission, and/or distribution of electric energy. \n \n \nElectric Distributor: \n \n \n“Electric Distributor” shall mean a Member that 1) owns or leases with rights equivalent to \nownership of electric distribution facilities that are used to provide electric distribution service to \nelectric load within the PJM Region; or 2) is a generation and transmission cooperative or a joint \nmunicipal agency that has a member that owns electric distribution facilities used to provide \nelectric distribution service to electric load within the PJM Region. \n \n \nEmergency: \n \n \n“Emergency” shall mean (i) an abnormal system condition requiring manual or automatic action \nto maintain system frequency, or to prevent loss of firm load, equipment damage, or tripping of \nsystem elements that could adversely affect the reliability of an electric system or the safety of \npersons or property; or (ii) a fuel shortage requiring departure from normal operating procedures \nin order to minimize the use of such scarce fuel; or (iii) a condition that requires implementation \nof emergency procedures as defined in the PJM Manuals. \n \n \nEnd-Use Customer: \n \n \n“End-Use Customer” shall mean a Member that is a retail end-user of electricity within the PJM \nRegion.  For purposes of Members Committee sector classification, a Member that is a retail \nend-user that owns generation may qualify as an End-Use customer if:  (1) the average physical \nunforced capacity owned by the Member and its affiliates in the PJM region over the five \nPlanning Periods immediately preceding the relevant Planning Period does not exceed the \naverage PJM capacity obligation for the Member and its affiliates over the same time period; or \n(2) the average energy produced by the Member and its affiliates within the PJM region over the \nfive Planning Periods immediately preceding the relevant Planning Period does not exceed the \naverage energy consumed by that Member and its affiliates within the PJM region over the same"},{"page":138,"startToken":53371,"endToken":53784,"text":"time period.  The foregoing notwithstanding, taking retail service may not be sufficient to qualify \na Member as an End-Use Customer. \n \n \n \nEnergy Efficiency Resource: \n \n \n“Energy Efficiency Resource” shall mean a project, including installation of more efficient \ndevices or equipment or implementation of more efficient processes or systems, meeting the \nrequirements of RAA, Schedule 6 and exceeding then-current building codes, appliance \nstandards, or other relevant standards, designed to achieve a continuous (during the periods \ndescribed in Reliability Assurance Agreement, Schedule 6 and the PJM Manuals) reduction in \nelectric energy consumption that is not reflected in the peak load forecast prepared for the \nDelivery Year for which the Energy Efficiency Resource is proposed, and that is fully \nimplemented at all times during such Delivery Year, without any requirement of notice, dispatch, \nor operator intervention.  Annual Energy Efficiency Resources, Base Capacity Energy Efficiency \nResources and Summer-Period Energy Efficiency Resources are types of Energy Efficiency \nResources. \n \nExigent Water Storage: \n \n“Exigent Water Storage” shall mean water stored in the pondage or reservoir of a hydropower \nresource which is not typically available during normal operating conditions (as those conditions \nare described in the relevant FERC hydropower license), but which can be drawn upon during \nemergency conditions (as described in the FERC hydropower license), including in order to \navoid a load shed.  In an effective load carrying capability analysis, exigent storage capability \nfrom an upstream hydro facility can be considered relative to a downstream hydro facility by \nassessing cascading storage and flows. \n \nExisting Demand Resource: \n \n“Existing Demand Resource” shall mean a Demand Resource for which the Demand Resource \nProvider has identified existing end-use customer sites that are registered for the current Delivery \nYear with PJM (even if not registered by such Demand Resource Provider) and that the Demand \nResource Provider reasonably expects to have under a contract to reduce load based on PJM \ndispatch instructions by the start of the Delivery Year for which such resource is offered. \n \nExisting DER Capacity Aggregation Resource: \n \n“Existing DER Capacity Aggregation Resource” shall mean a DER Capacity Aggregation \nResource for which the DER Aggregator has identified existing Component DER that are \nregistered in a DER Capacity Aggregation Resource for the current Delivery Year with PJM \n(even if not registered by such DER Aggregator) and that the DER Aggregator reasonably \nexpects to have under a contract to generate or reduce load based on PJM dispatch instructions \nby the start of the Delivery Year for which such DER Capacity Aggregation Resource is offered. \n \nExisting Generation Capacity Resource:"},{"page":139,"startToken":53784,"endToken":54223,"text":"“Existing Generation Capacity Resource” shall mean, for purposes of the must-offer requirement \nand mitigation of offers for any RPM Auction for a Delivery Year, a Generation Capacity \nResource that, as of the date on which bidding commences for such auction: (a) is in service; or \n(b) is not yet in service, but has cleared any RPM Auction for any prior Delivery Year.  A \nGeneration Capacity Resource shall be deemed to be in service if interconnection service has \never commenced (for resources located in the PJM Region), or if it is physically and electrically \ninterconnected to an external Control Area and is in full commercial operation (for resources not \nlocated in the PJM Region).  The additional megawatts of a Generation Capacity Resource that is \nbeing, or has been, modified to increase the number of megawatts of available installed capacity \nthereof shall not be deemed to be an Existing Generation Capacity Resource until such time as \nthose megawatts (a) are in service; or (b) are not yet in service, but have cleared any RPM \nAuction for any prior Delivery Year. \n \nExtended Summer Demand Resource: \n \n“Extended Summer Demand Resource” shall mean, for Delivery Years through May 31, 2018, \nand for FRR Capacity Plans Delivery Years through May 31, 2019, a resource that is placed \nunder the direction of the Office of the Interconnection and that will be available June through \nOctober and the following May, and will be available for an unlimited number of interruptions \nduring such months by the Office of the Interconnection, and will be capable of maintaining each \nsuch interruption for at least a 10-hour duration between the hours of 10:00AM to 10:00PM \nEastern Prevailing Time. The Extended Summer Demand Resource must be available June \nthrough October and the following May in the corresponding Delivery Year to be offered for sale \nor Self-Supplied in an RPM Auction, or included as an Extended Summer Demand Resource in \nan FRR Capacity Plan for the corresponding Delivery Year.   \n \n \nFacilities Study Agreement: \n \n \n“Facilities Study Agreement” shall have the same meaning as in Tariff, Part VI, section 206. \n \n \n \nFERC or Commission: \n \n \n“FERC” or “Commission” shall mean the Federal Energy Regulatory Commission or any \nsuccessor federal agency, commission or department exercising jurisdiction over the Tariff, \nOperating Agreement and Reliability Assurance Agreement. \n \n \nFirm Point-To-Point Transmission Service: \n \n \n“Firm Point-To-Point Transmission Service” shall have the meaning specified in the Tariff. \n \n \nFirm Service Level: \n \n“Firm Service Level” or “FSL” of Price Responsive Demand shall mean the level, determined at \na PRD Substation level, to which Price Responsive Demand shall be reduced during the Delivery \nYear when the Locational Marginal Price exceeds the price associated with such Price"},{"page":140,"startToken":54223,"endToken":54557,"text":"Responsive Demand identified by the PRD Provider in its PRD Plan. “Firm Service Level” or \n“FSL” of Demand Resource shall mean the pre-determined level to which an end-use customer’s \nload shall be reduced, upon notification from the Curtailment Service Provider’s market \noperations center or its agent. \n \nFirm Transmission Service: \n \n \n“Firm Transmission Service” shall mean transmission service that is intended to be available at \nall times to the maximum extent practicable, subject to an Emergency, an unanticipated failure of \na facility, or other event beyond the control of the owner or operator of the facility or the Office \nof the Interconnection. \n \n \nFixed Resource Requirement Alternative or FRR Alternative: \n \n \n“Fixed Resource Requirement Alternative” or “FRR Alternative” shall mean an alternative \nmethod for a Party to satisfy its obligation to provide Unforced Capacity hereunder, as set forth \nin the Reliability Assurance Agreement, Schedule 8.1. \n \nFixed-Tilt Solar Class: \n \n“Fixed-Tilt Solar Class” shall mean an ELCC Class consisting of Variable Resources that \nproduce electrical energy with solar panels that are primarily mounted in a fixed orientation. \n \n \nForecast Pool Requirement: \n \n \n“Forecast Pool Requirement” or “FPR” shall mean the amount equal to one plus the unforced \nreserve margin (stated as a decimal number) for the PJM Region required pursuant to this \nReliability Assurance Agreement, as approved by the PJM Board pursuant to Reliability \nAssurance Agreement, Schedule 4.1. \n \n \nFRR Capacity Plan or FRR Plan: \n \n \n“FRR Capacity Plan” or “FRR Plan” shall mean a long-term plan for the commitment of \nCapacity Resources and Price Responsive Demand to satisfy the capacity obligations of a Party \nthat has elected the FRR Alternative, as more fully set forth in the Reliability Assurance \nAgreement, Schedule 8.1. \n \n \nFRR Entity: \n \n \n“FRR Entity” shall mean, for the duration of such election, a Party that has elected the FRR \nAlternative hereunder. \n \n \nFRR Service Area: \n \n \n“FRR Service Area” shall mean (a) the service territory of an IOU as recognized by state law, \nrule or order; (b) the service area of a Public Power Entity or Electric Cooperative as recognized"},{"page":141,"startToken":54557,"endToken":54986,"text":"by franchise or other state law, rule, or order; or (c) a separately identifiable geographic area that \nis: (i) bounded by wholesale metering, or similar appropriate multi-site aggregate metering, that \nis visible to, and regularly reported to, the Office of the Interconnection, or that is visible to, and \nregularly reported to an Electric Distributor and such Electric Distributor agrees to aggregate the \nload data from such meters for such FRR Service Area and regularly report such aggregated \ninformation, by FRR Service Area, to the Office of the Interconnection; and (ii) for which the \nFRR Entity has or assumes the obligation to provide capacity for all load (including load growth) \nwithin such area.  In the event that the service obligations of an Electric Cooperative or Public \nPower Entity are not defined by geographic boundaries but by physical connections to a defined \nset of customers, the FRR Service Area in such circumstances shall be defined as all customers \nphysically connected to transmission or distribution facilities of such Electric Cooperative or \nPublic Power Entity within an area bounded by appropriate wholesale aggregate metering as \ndescribed above.   \n \n \nFull Program Option: \n \n“Full Program Option” shall mean participation in Emergency Load Response Program or Pre-\nEmergency Program which allows, pursuant to Tariff, Attachment DD and as applicable, (i) an \nenergy payment for load reductions during a pre-emergency or emergency event, and (ii) a \ncapacity payment for the ability to reduce load during a pre-emergency or emergency event. \n \nFull Requirements Service: \n \n \n“Full Requirements Service” shall mean wholesale service to supply all of the power needs of a \nLoad Serving Entity to serve end-users within the PJM Region that are not satisfied by its own \ngenerating facilities. \n \nGas Combined Cycle Class: \n \n“Gas Combined Cycle Class” shall mean an ELCC Class consisting of Unlimited Resources of \nthe combined cycle technology type that is primarily fueled by natural gas, but does not meet the \nrequirements to be included in the Gas Combined Cycle Dual Fuel Class. \n \nGas Combined Cycle Dual Fuel Class: \n \n“Gas Combined Cycle Dual Fuel Class” shall mean an ELCC Class consisting of Unlimited \nResources of the combined cycle technology type that is primarily fueled by natural gas, and that \nattests that it has the capability to start independently using onsite sources and operate \nindependently on alternate onsite fuel source(s) up to its maximum capacity level during the \nwinter season of the applicable Delivery Year in which it is providing capacity, and capable of \noperating on the alternate fuel for two 16-hour periods over two consecutive days at its \nmaximum capacity level.  \n \nGas Combustion Turbine Class:"},{"page":142,"startToken":54986,"endToken":55464,"text":"“Gas Combustion Turbine Class” shall mean an ELCC Class consisting of Unlimited Resources \nof the combustion turbine technology type that is primarily fueled by natural gas, but does not \nmeet the requirements to be included in the Gas Combustion Turbine Dual Fuel Class. \n \nGas Combustion Turbine Dual Fuel Class: \n \n“Gas Combustion Turbine Dual Fuel Class” shall mean an ELCC Class consisting of Unlimited \nResources of the combustion turbine technology type that is primarily fueled by natural gas, and \nattests that it has the capability to start independently using onsite sources and operate \nindependently on alternate onsite fuel source(s) up to its maximum capacity level during the \nwinter season of the applicable Delivery Year in which it is providing capacity, and capable of \noperating on the alternate fuel for two 16-hour periods over two consecutive days at its \nmaximum capacity level. \n \n \nGeneration Capacity Resource: \n \n \n“Generation Capacity Resource” shall mean a Generating Facility, or the contractual right to \ncapacity from a specified Generating Facility, that meets the requirements of RAA, Schedule 9 \nand RAA, Schedule 10, and, for Generating Facilities that are committed to an FRR Capacity \nPlan, that meets the requirements of RAA, Schedule 8.1.  A Generation Capacity Resource may \nbe an Existing Generation Capacity Resource or a Planned Generation Capacity Resource.  \n \nGeneration Owner: \n \n \n“Generation Owner” shall mean a Member that owns or leases with rights equivalent to \nownership, or otherwise controls and operates one or more operating generation resources \nlocated in the PJM Region.  The foregoing notwithstanding, for a planned generation resource to \nqualify a Member as a Generation Owner, such resource shall have cleared an RPM auction, and \nfor Energy Resources, the resource shall have a FERC-jurisdictional interconnection agreement \nor wholesale market participation agreement within PJM.   Purchasing all or a portion of the \noutput of a generation resource shall not be sufficient to qualify a Member as a Generation \nOwner.  For purposes of Members Committee sector classification, a Member that is primarily a \nretail end-user of electricity that owns generation may qualify as a Generation Owner if:  (1) the \ngeneration resource is the subject of a FERC-jurisdictional interconnection agreement or \nwholesale market participation agreement within PJM; (2) the average physical unforced \ncapacity owned by the Member and its affiliates over the five Planning Periods immediately \npreceding the relevant Planning Period exceeds the average PJM capacity obligation of the \nMember and its affiliates over the same time period; and (3) the average energy produced by the \nMember and its affiliates within PJM over the five Planning Periods immediately preceding the \nrelevant Planning Period exceeds the average energy consumed by the Member and its affiliates \nwithin PJM over the same time period. \n \n \nGenerator Forced Outage: \n \n \n“Generator Forced Outage” shall mean an immediate reduction in output or capacity or removal \nfrom service, in whole or in part, of a generating unit by reason of an Emergency or threatened"},{"page":143,"startToken":55464,"endToken":55915,"text":"Emergency, unanticipated failure, or other cause beyond the control of the owner or operator of \nthe facility, as specified in the relevant portions of the PJM Manuals.  A reduction in output or \nremoval from service of a generating unit in response to changes in market conditions shall not \nconstitute a Generator Forced Outage. \n \n \nGenerator Maintenance Outage: \n \n \n“Generator Maintenance Outage” shall mean the scheduled removal from service, in whole or in \npart, of a generating unit in order to perform repairs on specific components of the facility, if \nremoval of the facility qualifies as a maintenance outage pursuant to the PJM Manuals. \n \n \nGenerator Planned Outage: \n \n \n“Generator Planned Outage” shall mean the scheduled removal from service, in whole or in part, \nof a generating unit for inspection, maintenance or repair with the approval of the Office of the \nInterconnection in accordance with the PJM Manuals. \n \n \nGood Utility Practice: \n \n \n“Good Utility Practice” shall mean any of the practices, methods and acts engaged in or \napproved by a significant portion of the electric utility industry during the relevant time period, \nor any of the practices, methods and acts which, in the exercise of reasonable judgment in light \nof the facts known at the time the decision was made, could have been expected to accomplish \nthe desired result at a reasonable cost consistent with good business practices, reliability, safety \nand expedition.  Good Utility Practice is not intended to be limited to the optimum practice, \nmethod, or act to the exclusion of all others, but rather is intended to include acceptable \npractices, methods, or acts generally accepted in the region; including those practices required by \nFederal Power Act Section 215(a)(4).  \n \n \nHybrid Resource Class: \n \n“Hybrid Resource Class” shall mean the ELCC Classes specified in RAA Schedules 9.1 and 9.2 \nSection B.  Each Hybrid Resource Class has a specified combination of two components, \nwhereby, absent being part of a Combination Resource, the individual components would be in a \nCapacity Storage Resource Class, a Variable Resource Class or would be an Unlimited \nResource.  A resource that is a member of a Hybrid Resource Class has a single Point Of \nInterconnection, unless the resource is controlled in an integrated fashion, is at a single site, and \nis approved by PJM to be considered a single resource in accordance with the PJM Manuals. \n \nHydropower With Non-Pumped Storage: \n \n“Hydropower With Non-Pumped Storage” shall mean a hydropower facility that can capture and \nstore incoming stream flow, without use of pumps, in pondage or a reservoir, and the Generation \nOwner has the ability, within the constraints available in the applicable operating license, to exert \nmaterial control over the quantity of stored water and output of the facility throughout an \nOperating Day."},{"page":144,"startToken":55915,"endToken":56239,"text":"Hydropower With Non-Pumped Storage Class: \n \n“Hydropower With Non-Pumped Storage Class” shall mean an ELCC Class consisting of \nCombination Resources that are Hydropower With Non-Pumped Storage resources. \n \nIncremental Auction: \n \n \n“Incremental Auction” shall mean any of several auctions conducted for a Delivery Year after \nthe Base Residual Auction for such Delivery Year and before the first day of such Delivery Year, \nincluding the First Incremental Auction, Second Incremental Auction, Third Incremental \nAuction, or Conditional Incremental Auction.  Incremental Auctions (other than the Conditional \nIncremental Auction), shall be held for the purposes of: \n \n(i) \nallowing Market Sellers that committed Capacity Resources in the Base Residual \nAuction for a Delivery Year, which subsequently are determined to be unavailable \nto deliver the committed Unforced Capacity in such Delivery Year (due to \nresource retirement, resource cancellation or construction delay, resource \nderating, EFORd increase, Accredited UCAP Factor decrease, a decrease in the \nNominated Demand Resource Value of a Planned Demand Resource, delay or \ncancellation of a Qualifying Transmission Upgrade, or similar occurrences) to \nsubmit Buy Bids for replacement Capacity Resources; and  \n \n(ii) \nallowing the Office of the Interconnection to reduce or increase the amount of \ncommitted capacity secured in prior auctions for such Delivery Year if, as a result \nof changed circumstances or expectations since the prior auction(s), there is, \nrespectively, a significant excess or significant deficit of committed capacity for \nsuch Delivery Year, for the PJM Region or for an LDA. \n \n \nIntermittent Hydropower Class: \n \n“Intermittent Hydropower Class” shall mean an ELCC Class consisting of Variable Resources \nthat are run-of-river hydropower generators that must generally pass incoming water and \ntherefore cannot appreciably store water to later increase the output of the facility. Resources in \nthe Intermittent Hydropower Class are not Hydropower with Non-Pumped Storage resources. \n \nIOU: \n \n \n“IOU” shall mean an investor-owned utility with substantial business interest in owning and/or \noperating electric facilities in any two or more of the following three asset categories:  \ngeneration, transmission, distribution. \n \nIntermittent Landfill Gas Class:"},{"page":145,"startToken":56239,"endToken":56707,"text":"“Intermittent Landfill Gas Class” shall mean an ELCC Class consisting of Variable Resources \nfueled by landfill gas that, because of fuel availability patterns, cannot run consistently at \ninstalled capacity levels for 24 or more hours. \n \nLarge Load Adjustment: \n \n“Large Load Adjustment” shall mean any MW quantity of adjustments to summer peak load at \nthe “zone/area” level and summed by Zone as further detailed in PJM Manuals.  For purposes of \nthis definition, a “zone/area” is an area within a Zone for which the relevant Electric Distributor \nspecifies a separate Obligation Peak Load MW value.  A zone/area is a service area of an \nElectric Distributor that is a separately identifiable, geographic area bounded by wholesale \nmetering (e.g., the service territory of an operating company of a Transmission Owner). \n \nLimited Demand Resource: \n \n \n“Limited Demand Resource” shall mean, for Delivery Years through May 31, 2018, and for FRR \nCapacity Plans Delivery Years through May 31, 2019, a resource that is placed under the \ndirection of the Office of the Interconnection and that will, at a minimum, be available for \ninterruption for at least 10 Load Management Events during the summer period of June through \nSeptember in the Delivery Year, and will be capable of maintaining each such interruption for at \nleast a 6-hour duration.  At a minimum, the Limited Demand Resource shall be available for \nsuch interruptions on weekdays, other than NERC holidays, from 12:00PM (noon) to 8:00PM \nEastern Prevailing Time.  The Limited Demand Resource must be available during the summer \nperiod of June through September in the corresponding Delivery Year to be offered for sale or \nSelf-Supplied in an RPM Auction, or included as a Limited Demand Resource in an FRR \nCapacity Plan for the corresponding Delivery Year. \n \nLimited Duration Resource: \n \n“Limited Duration Resource” shall mean a Generation Capacity Resource or a generation \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource, that is not a Variable Resource, that is not a Combination Resource, and \nthat is not capable of running continuously at Maximum Facility Output for 24 hours or longer.  \nA Capacity Storage Resource is a Limited Duration Resource. \n \n \nLoad Serving Entity or LSE: \n \n \n“Load Serving Entity” or “LSE” shall mean any entity (or the duly designated agent of such an \nentity), including a load aggregator or power marketer, (i) serving end-users within the PJM \nRegion, and (ii) that has been granted the authority or has an obligation pursuant to state or local \nlaw, regulation or franchise to sell electric energy to end-users located within the PJM Region.  \nLoad Serving Entity shall include any end-use customer that qualifies under state rules or a \nutility retail tariff to manage directly its own supply of electric power and energy and use of \ntransmission and ancillary services. \n \n \nLocational Reliability Charge:"},{"page":146,"startToken":56707,"endToken":56978,"text":"“Locational Reliability Charge” shall mean the charge determined pursuant to RAA, Article 7, \nsection 2. \n \n \nMarkets and Reliability Committee: \n \n \n“Markets and Reliability Committee” shall mean the committee established pursuant to the \nOperating Agreement as a Standing Committee of the Members Committee.  \n \n \nMaximum Emergency Service Level: \n \n“Maximum Emergency Service Level” or “MESL” of Price Responsive Demand for the \n2017/2018 through the 2021/2022 Delivery Years shall mean the level, determined at a PRD \nSubstation level, to which Price Responsive Demand shall be reduced during the Delivery Year \nwhen a Maximum Generation Emergency is declared and the Locational Marginal Price exceeds \nthe price associated with such Price Responsive Demand identified by the PRD Provider in its \nPRD Plan. \n \nMember: \n \n \n“Member” shall have the meaning provided in the Operating Agreement. \n \n \nMembers Committee: \n \n \n“Members Committee” shall mean the committee specified in Operating Agreement, section 8 \ncomposed of the representatives of all the Members. \n \n \nNERC: \n \n \n“NERC” shall mean the North American Electric Reliability Corporation or any successor \nthereto. \n \nNetwork External Designated Transmission Service: \n \n“Network External Designated Transmission Service” shall mean the quantity of network \ntransmission service confirmed by PJM for use by a market participant to import power and \nenergy from an identified Generation Capacity Resource located outside the PJM Region, upon \ndemonstration by such market participant that it owns such Generation Capacity Resource, has \nan executed contract to purchase power and energy from such Generation Capacity Resource, or \nhas a contract to purchase power and energy from such Generation Capacity Resource contingent \nupon securing firm transmission service from such resource. \n \nNetwork Resources: \n \n \n“Network Resources” shall have the meaning set forth in the PJM Tariff."},{"page":147,"startToken":56978,"endToken":57235,"text":"Network Transmission Service: \n \n \n“Network Transmission Service” shall mean transmission service provided pursuant to the rates, \nterms and conditions set forth in Tariff, Part III or transmission service comparable to such \nservice that is provided to a Load Serving Entity that is also a Transmission Owner. \n \nNominal PRD Value:  \n \n“Nominal PRD Value” shall mean, as to any PRD Provider, an adjustment, determined in \naccordance with Reliability Assurance Agreement, Schedule 6.1, to the peak-load forecast used \nto determine the quantity of capacity sought through an RPM Auction, reflecting the aggregate \neffect of Price Responsive Demand on peak load resulting from the Price Responsive Demand to \nbe provided by such PRD Provider.    \n \nNominated Demand Resource Value: \n \n \n“Nominated Demand Resource Value” shall have the meaning specified in Tariff, Attachment \nDD. \n \n \nNon-Retail Behind the Meter Generation: \n \n \n“Non-Retail Behind the Meter Generation” shall mean Behind the Meter Generation that is used \nby municipal electric systems, electric cooperatives, and electric distribution companies to serve \nload. \n \n \nNuclear Class: \n \n“Nuclear Class” shall mean an ELCC Class consisting of Unlimited Resources primarily fueled \nby nuclear fuel. \n \nObligation Peak Load: \n \n \n“Obligation Peak Load” shall have the meaning specified in Reliability Assurance Agreement, \nSchedule 8. \n \n \nOffice of the Interconnection: \n \n \n“Office of the Interconnection” shall mean the employees and agents of PJM Interconnection, \nL.L.C., subject to the supervision and oversight of the PJM Board, acting pursuant to the \nOperating Agreement. \n \nOffshore Wind Class: \n \n“Offshore Wind Class” shall mean an ELCC Class consisting of Variable Resources that produce \nelectrical energy with offshore wind turbines located in the ocean."},{"page":148,"startToken":57235,"endToken":57614,"text":"Onshore Wind Class: \n \n“Onshore Wind Class” shall mean an ELCC Class consisting of Variable Resources that produce \nelectrical energy using wind turbines and that are not in the Offshore Wind Class. \n \n \nOperating Agreement of the PJM Interconnection, L.L.C., Operating Agreement or PJM \nOperating Agreement: \n \n \n“Operating Agreement of the PJM Interconnection, L.L.C.,”  “Operating Agreement” or “PJM \nOperating Agreement” shall mean that agreement, dated as of April 1, 1997 and as amended and \nrestated as of June 2, 1997, including all Schedules, Exhibits, Appendices, addenda or \nsupplements hereto, as amended from time to time thereafter, among the Members of the PJM \nInterconnection, L.L.C, on file with the Commission. \n \n \nOperating Day: \n \n“Operating Day” shall have the same meaning as provided in the Operating Agreement. \n \n \nOperating Reserve: \n \n \n“Operating Reserve” shall mean the amount of generating capacity scheduled to be available for \na specified period of an Operating Day to ensure the reliable operation of the PJM Region, as \nspecified in the PJM Manuals. \n \nOrdinary Water Storage: \n \n“Ordinary Water Storage” shall mean water stored in the pondage or reservoir of a hydropower \nresource which is typically available during normal operating conditions pursuant to the FERC \nlicense governing the operation of the hydropower resource. \n \n \nOther Limited Duration Class: \n \n“Other Limited Duration Class” shall mean the ELCC Classes specified in RAA Schedules 9.1 \nand 9.2 section B of this Agreement, each of which has a specified characteristic duration and \nconsists of Limited Duration Resources that are not Capacity Storage Resources. The \ncharacteristic duration of an Other Limited Duration Class is the maximum period of time \nrepresented in the ELCC model that the resources of the class can run at a stated capability. \n \nOther Limited Duration Combination Class: \n \n“Other Limited Duration Combination Class” shall mean the ELCC Classes specified in RAA \nSchedules 9.1 and 9.2 section B. Each Other Limited Duration Class has a specified combination \nof two components, whereby, absent being part of a Combination Resource, one component \nwould be in an Other Limited Duration Class, and the other component would be in a Variable \nResource Class or would be an Unlimited Resource. A resource that is a member of an Other \nLimited Duration Combination Class has a single Point Of Interconnection, unless the resource is"},{"page":149,"startToken":57614,"endToken":57976,"text":"controlled in an integrated fashion, is at a single site, and is approved by PJM to be considered a \nsingle resource in accordance with the PJM Manuals. \n \nOther Supplier: \n \n \n“Other Supplier” shall mean a Member that: (i) is engaged in buying, selling or transmitting \nelectric energy, capacity, ancillary services, Financial Transmission Rights or other services \navailable under PJM’s governing documents in or through the Interconnection or has a good faith \nintent to do so, and (ii) is not a Generation Owner, Electric Distributor, Transmission Owner or \nEnd-Use Customer. \n \n \nOther Unlimited Resource Class: \n \n“Other Unlimited Resource Class” shall mean an ELCC Class consisting of Unlimited Resources \nthat do not qualify for any other ELCC Class specified in RAA Schedule 9.2, section D. \n \nOther Variable Resource Class: \n \n“Other Variable Resource Class” shall mean an ELCC Class consisting of Variable Resources \nthat are not in any other Variable Resource class, including Variable Resources that are \ncomposed of multiple components, each of which would be a Variable Resource. A resource \ncomposed of both fixed-tilt solar panels and tracking solar panels is not in this class. A resource \nthat is a member of a Other Variable Resource Class has a single Point Of Interconnection, \nunless the resource is controlled in an integrated fashion, is at a single site, and is approved by \nPJM to be considered a single resource in accordance with the PJM Manuals. \n \nPartial Requirements Service: \n \n \n“Partial Requirements Service” shall mean wholesale service to supply a specified portion, but \nnot all, of the power needs of a Load Serving Entity to serve end-users within the PJM Region \nthat are not satisfied by its own generating facilities. \n \nParty: \n \n“Party” shall mean an entity bound by the terms of the Operating Agreement. \n \nPeak Shaving Adjustment:  \n \n“Peak Shaving Adjustment” shall mean a load forecast mechanism that allows load reductions by \nend-use customers to result in a downward adjustment of the summer load forecast for the \nassociated Zone. Any End-Use Customer identified in an approved peak shaving plan shall not \nalso participate in PJM Markets as Price Responsive Demand, Demand Resource, Base Capacity \nDemand Resource, Capacity Performance Demand Resource, or Economic Load Response \nParticipant. \n \nPercentage Internal Resources Required:"},{"page":150,"startToken":57976,"endToken":58258,"text":"“Percentage Internal Resources Required” shall mean, for purposes of an FRR Capacity Plan, the \npercentage of the LDA Reliability Requirement for an LDA that must be satisfied with Capacity \nResources located in such LDA. \n \nPerformance Assessment Interval: \n \n“Performance Assessment Interval” shall have the meaning specified in Tariff, Attachment DD. \n \n \nPJM: \n \n \n“PJM” shall mean PJM Interconnection, L.L.C., including the Office of the Interconnection as \nreferenced in the PJM Operating Agreement.  When such term is being used in the RAA it shall \nalso include the PJM Board. \n \n \nPJM Board: \n \n \n“PJM Board” shall mean the Board of Managers of the  LLC, acting pursuant to the Operating \nAgreement, except when such term is being used in Tariff, Attachment M, in which case PJM \nBoard shall mean the Board of Managers of PJM or its designated representative, exclusive of \nany members of PJM Management. \n \n \nPJM Manuals: \n \n \n“PJM Manuals” shall mean the instructions, rules, procedures and guidelines established by the \nOffice of the Interconnection for the operation, planning and accounting requirements of the PJM \nRegion. \n \nPJM Region: \n \n \n“PJM Region” shall have the same meaning as provided in the Operating Agreement. \n \n \nPJM Region Installed Reserve Margin: \n \n \n“PJM Region Installed Reserve Margin” shall mean the percent installed reserve margin for the \nPJM Region required pursuant to Reliability Assurance Agreement, Schedule 4.1, as approved \nby the PJM Board. \n \nPJM Tariff, Tariff, O.A.T.T., OATT or PJM Open Access Transmission Tariff: \n \n \n“PJM Tariff,” “Tariff,” “O.A.T.T., “OATT” or “PJM Open Access Transmission Tariff” shall \nmean that certain PJM Open Access Transmission Tariff, including any schedules, appendices, \nor exhibits attached thereto, on file with FERC and as amended from time to time thereafter. \n \n \nPlanned Demand Resource:"},{"page":151,"startToken":58258,"endToken":58840,"text":"“Planned Demand Resource” shall mean any Demand Resource that does not currently have the \ncapability to provide a reduction in demand or to otherwise control load, but that is scheduled to \nbe capable of providing such reduction or control on or before the start of the Delivery Year for \nwhich such resource is to be committed, as determined in accordance with the requirements of \nReliability Assurance Agreement, Schedule 6.  As set forth in Reliability Assurance Agreement, \nSchedule 6 and Reliability Assurance Agreement, Schedule 8.1, a Demand Resource Provider \nsubmitting a DR Sell Offer Plan shall identify as Planned Demand Resources in such plan all \nDemand Resources in excess of those that qualify as Existing Demand Resources. \n \n \nPlanned DER Capacity Aggregation Resource: \n \nA “Planned DER Capacity Aggregation Resource” shall mean any DER Capacity Aggregation \nResource that does not currently have the capability to provide generation or reduction in \ndemand, but that is scheduled to be capable of providing such generation or reduction in demand \non or before the start of the Delivery Year for which such resource is to be committed, as \ndetermined in accordance with the requirements of Reliability Assurance Agreement, Schedule \n6.2.  As set forth in Reliability Assurance Agreement, Schedule 6.2 and Reliability Assurance \nAgreement, Schedule 8.1, a DER Aggregator submitting a DER Capacity Aggregation Resource \nSell Offer Plan shall identify in such plan all DER Capacity Aggregation Resources in excess of \nthose that qualify as Existing DER Capacity Aggregation Resources.  A Planned DER Capacity \nAggregation Resource must comply with all provisions of the DER Aggregator Participation \nModel described in Tariff, Attachment K-Appendix, section 1.4B and Operating Agreement, \nSchedule 1, section 1.4B, prior to the applicable Delivery Year. \n \nPlanned External Generation Capacity Resource: \n \n \n“Planned External Generation Capacity Resource” shall mean a proposed Generation Capacity \nResource, or a proposed increase in the capability of a Generation Capacity Resource, that (a) is \nto be located outside the PJM Region, (b) participates in the generation interconnection process \nof a Control Area external to PJM, (c) is scheduled to be physically and electrically \ninterconnected to the transmission facilities of such Control Area on or before the first day of the \nDelivery Year for which such resource is to be committed to satisfy the reliability requirements \nof the PJM Region, and (d) is in full commercial operation prior to the first day of such Delivery \nYear, such that it is sufficient to provide the Installed Capacity set forth in the Sell Offer forming \nthe basis of such resource’s commitment to the PJM Region.  Prior to participation in any Base \nResidual Auction for such Delivery Year, the Capacity Market Seller must demonstrate that it \nhas documentation which is functionally equivalent to an approved Decision Point I submission \nunder the PJM Tariff Part VII or VIII as applicable or, for resources which are greater than \n20MWs participating in a Base Residual Auction for the 2019/2020 Delivery Year and \nsubsequent Delivery Years, an agreement or other documentation which is functionally \nequivalent to an approved Decision Point II submission under the PJM Tariff Part VII or VIII as \napplicable, with the transmission owner to whose transmission facilities or distribution facilities \nthe resource is being directly connected, and, as applicable, the transmission provider.  Prior to \nparticipating in any Incremental Auction for such Delivery Year, the Capacity Market Seller \nmust demonstrate it has entered into an interconnection agreement, or such other documentation \nthat is functionally equivalent to a Generation Interconnection Agreement under the PJM Tariff,"},{"page":152,"startToken":58840,"endToken":59439,"text":"with the transmission owner to whose transmission facilities or distribution facilities the resource \nis being directly connected, and, as applicable, the transmission provider.  A Planned External \nGeneration Capacity Resource must provide evidence to PJM that it has been studied as a \nNetwork Resource, or such other similar interconnection product in such external Control Area, \nmust provide contractual evidence that it has applied for or purchased transmission service to be \ndeliverable to the PJM border, and must provide contractual evidence that it has applied for \ntransmission service to be deliverable to the bus at which energy is to delivered, the agreements \nfor which must have been executed prior to participation in any Reliability Pricing Model \nAuction for such Delivery Year. Any such resource shall cease to be considered a Planned \nExternal Generation Capacity Resource as of the earlier of (i) the date that interconnection \nservice commences as to such resource; or (ii) the resource has cleared an RPM Auction, in \nwhich case it shall become an Existing Generation Capacity Resource for purposes of the \nmitigation of offers for any RPM Auction for all subsequent Delivery Years.   \n \n \nPlanned Generation Capacity Resource: \n \n \n“Planned Generation Capacity Resource” shall mean a Generation Capacity Resource, or \nadditional megawatts to increase the size of a Generation Capacity Resource that is being or has \nbeen modified to increase the number of megawatts of available installed capacity thereof,  \nparticipating in the generation interconnection process under Tariff, Part IV, Subpart A, Part VII \nor Part VIII, as applicable, for which: (i) Interconnection Service is scheduled to commence on \nor before the first day of the Delivery Year for which such resource is to be committed to RPM \nor to an FRR Capacity Plan; (ii) for any such resource seeking to offer into a Base Residual \nAuction, or for any such resource of 20 MWs or less seeking to offer into a Base Residual \nAuction, all the requirements for an approved Decision Point I submission have been met under \nTariff Part VII or VIII (or, for resources for which a Decision Point I submission is not required, \nhas such other agreement or documentation that is functionally equivalent to a an approved \nDecision Point I submission) prior to the Base Residual Auction for such Delivery Year; (iii) for \nany such resource of more than 20 MWs seeking to offer into a Base Residual Auction for the \n2019/2020 Delivery Year and subsequent Delivery Years, all the requirements for an approved \nDecision Point II submission have been met under Tariff Part VII or VIII (or, for resources for \nwhich a Decision Point II submission is not required, has such other agreement or documentation \nthat is functionally equivalent to an approved Decision Point II submission) has been executed \nprior to the Base Residual Auction for such Delivery Year; and (iv) a Generation Interconnection \nAgreement or Wholesale Market Participation Agreement has been executed prior to any \nIncremental Auction for such Delivery Year in which such resource plans to participate.  \nNotwithstanding the foregoing, a Planned Generation Capacity Resource shall also include any \ngeneration resources that are committed through the Reliability Backstop Procurement.  For \npurposes of the must-offer requirement and mitigation of offers for any RPM Auction for a \nDelivery Year, a Generation Capacity Resource shall cease to be considered a Planned \nGeneration Capacity Resource as of the earlier of (i) the date that Interconnection Service \ncommences as to such resource; or (ii) the resource has cleared an RPM Auction for any \nDelivery Year, in which case it shall become an Existing Generation Capacity Resource for any \nRPM Auction for all subsequent Delivery Years.   \n \n \nPlanning Period:"},{"page":153,"startToken":59439,"endToken":59782,"text":"“Planning Period” shall mean the 12 months beginning June 1 and extending through May 31 of \nthe following year, or such other period approved by the Members Committee. \n \n \nPortfolio Expected Unserved Energy: \n \n“Portfolio Expected Unserved Energy” shall mean the annual amount of expected unserved \nenergy, in MWh, that is expected for the RTO when at the annual reliability criteria that provides \nan acceptable level of reliability consistent with the Reliability Principles and Standards. \n \nPRD Curve: \n \n“PRD Curve” shall mean a price-consumption curve at a PRD Substation level, if available, and \notherwise at a Zonal (or sub-Zonal LDA, if applicable) level, that details the base consumption \nlevel of Price Responsive Demand and the decreasing consumption levels at increasing prices. \n \nPRD Provider:  \n \n“PRD Provider” shall mean a PJM Member that has entered contractual arrangements with end-\nuse customers that satisfy the eligibility criteria for and provides Price Responsive Demand. \n \nPRD Provider’s Zonal Expected Peak Load Value of PRD:  \n \n“PRD Provider’s Zonal Expected Peak Load Value of PRD” shall mean the expected \ncontribution to Delivery Year peak load of a PRD Provider’s Price Responsive Demand, were \nsuch demand not to be reduced in response to price, based on the contribution of the end-use \ncustomers comprising such Price Responsive Demand to the most recent prior Delivery Year’s \npeak demand, escalated to the Delivery Year in question, as determined in a manner consistent \nwith the Office of the Interconnection’s load forecasts used for purposes of the RPM Auctions. \n \nPRD Reservation Price: \n \n“PRD Reservation Price” shall mean an RPM Auction clearing price identified in a PRD Plan for \nPrice Responsive Demand load below which the PRD Provider desires not to commit the \nidentified load as Price Responsive Demand. \n  \nPRD Substation: \n \n“PRD Substation” shall mean an electrical substation that is located in the same Zone or in the \nsame sub-Zonal LDA as the end-use customers identified in a PRD Plan or PRD registration and \nthat, in terms of the electrical topography of the Transmission Facilities comprising the PJM \nRegion, is as close as practicable to such loads. \n \nPrice Responsive Demand:"},{"page":154,"startToken":59782,"endToken":60154,"text":"“Price Responsive Demand” or “PRD” shall mean end-use customer load registered by a PRD \nProvider pursuant to Reliability Assurance Agreement, Schedule 6.1 that have, as set forth in \nmore detail in the PJM Manuals, the metering capability to record electricity consumption at an \ninterval of one hour or less, Supervisory Control capable of curtailing such load (consistent with \napplicable RERRA requirements) at each PRD Substation identified in the relevant PRD Plan or \nPRD registration in response to a Performance Assessment Interval that triggers a PRD \nperformance assessment or a Non-PAI Event, and a retail rate structure, or equivalent contractual \narrangement, capable of changing retail rates as frequently as an hourly basis, that is linked to or \nbased upon changes in real-time Locational Marginal Prices at a PRD Substation level and that \nresults in a predictable automated response to varying wholesale electricity prices. \n \nPrice Responsive Demand Credit: \n \n“Price Responsive Demand Credit” shall mean a credit, based on committed Price Responsive \nDemand, as determined under Reliability Assurance Agreement, Schedule 6.1. \n \nPrice Responsive Demand Plan or PRD Plan: \n \n“Price Responsive Demand Plan” or “PRD Plan” shall mean a plan, submitted by a PRD \nProvider and received by the Office of the Interconnection in accordance with Reliability \nAssurance Agreement, Schedule 6.1 and procedures specified in the PJM Manuals, claiming a \npeak demand limitation due to Price Responsive Demand to support the determination of such \nPRD Provider’s Nominal PRD Value. \n \nPublic Power Entity: \n \n \n“Public Power Entity” shall mean any agency, authority, or instrumentality of a state or of a \npolitical subdivision of a state, or any corporation wholly owned by any one or more of the \nforegoing, that is engaged in the generation, transmission, and/or distribution of electric energy. \n \n \nQualifying Transmission Upgrades: \n \n \n“Qualifying Transmission Upgrades” shall have the meaning specified in Tariff, Attachment DD. \n \n \nRelevant Electric Retail Regulatory Authority: \n \n“Relevant Electric Retail Regulatory Authority” or “RERRA” shall have the meaning specified \nin the PJM Operating Agreement. \n \nReliability Principles and Standards: \n \n \n“Reliability Principles and Standards” shall mean the principles and standards established by  the \nOffice of the Interconnection that define, among other things, an acceptable probabilistic of loss \nof load criteria due to inadequate generation or transmission capability, as amended from time to \ntime."},{"page":155,"startToken":60154,"endToken":60521,"text":"Required Approvals: \n \n \n“Required Approvals” shall mean all of the approvals required for the Operating Agreement to \nbe modified or to be terminated, in whole or in part, including the acceptance for filing by FERC \nand every other regulatory authority with jurisdiction over all or any part of the Operating \nAgreement. \n \n \nSelf-Supply: \n \n \n“Self-Supply” shall have the meaning provided in Tariff, Attachment DD. \n \nSmall Commercial Customer: \n \n“Small Commercial Customer” shall have the same meaning as in the PJM Tariff. \n \n \nState Consumer Advocate: \n \n \n“State Consumer Advocate” shall mean a legislatively created office from any State, all or any \npart of the territory of which is within the PJM Region, and the District of Columbia established, \ninter alia, for the purpose of representing the interests of energy consumers before the utility \nregulatory commissions of such states and the District of Columbia and the FERC.  \n \n \nState Regulatory Structural Change: \n \n \n“State Regulatory Structural Change” shall mean as to any Party, a state law, rule, or order that, \nafter September 30, 2006, initiates a program that allows retail electric consumers served by such \nParty to choose from among alternative suppliers on a competitive basis, terminates such a \nprogram, expands such a program to include classes of customers or localities served by such \nParty that were not previously permitted to participate in such a program, or that modifies retail \nelectric market structure or market design rules in a manner that materially increases the \nlikelihood that a substantial proportion of the customers of such Party that are eligible for retail \nchoice under such a program (a) that have not exercised such choice will exercise such choice; or \n(b) that have exercised such choice will no longer exercise such choice, including for example, \nwithout limitation, mandating divestiture of utility-owned generation or structural changes to \nsuch Party’s default service rules that materially affect whether retail choice is economically \nviable. \n \nSteam Class: \n \n“Steam Class” shall mean an ELCC Class consisting of Unlimited Resources of the steam \ntechnology type and the primary fuel is not coal or nuclear. \n \nSummer-Period Demand Resource: \n \nSummer-Period Demand Resource shall mean, for the 2020/2021 Delivery Year and subsequent \nDelivery Years, a resource that is placed under the direction of the Office of the Interconnection,"},{"page":156,"startToken":60521,"endToken":60999,"text":"and will be available June through October and the following May of the Delivery Year, and will \nbe available for an unlimited number of interruptions during such months by the Office of the \nInterconnection, and will be capable of maintaining each such interruption between the hours of \n10:00AM to 10:00PM Eastern Prevailing Time.  The Summer-Period Demand Resource must be \navailable June through October and the following May in the corresponding Delivery Year to be \noffered for sale in an RPM Auction, or included as a Summer-Period Demand Resource in an \nFRR Capacity Plan for the corresponding Delivery Year. \n \nSummer-Period Energy Efficiency Resource:  \n \nSummer-Period Energy Efficiency Resource shall mean, for the 2020/2021 Delivery Year and \nsubsequent Delivery Years, a project, including installation of more efficient devices or \nequipment or implementation of more efficient processes or systems, meeting the requirements \nof Reliability Assurance Agreement, Schedule 6 and exceeding then-current building codes, \nappliance standards, or other relevant standards, designed to achieve a continuous (during the \nsummer peak periods as described in Reliability Assurance Agreement, Schedule 6 and the PJM \nManuals) reduction in electric energy consumption that is not reflected in the peak load forecast \nprepared for the Delivery Year for which the Summer-Period Energy Efficiency Resource is \nproposed, and that is fully implemented at all times during such Delivery Year, without any \nrequirement of notice, dispatch, or operator intervention. \n \nSupervisory Control: \n \n“Supervisory Control” shall mean the capability to curtail, in accordance with applicable \nRERRA requirements, load registered as Price Responsive Demand at each PRD Substation \nidentified in the relevant PRD Plan or PRD registration in response to a Maximum Generation \nEmergency declared by the Office of the Interconnection.  Except to the extent automation is not \nrequired by the provisions of the Operating Agreement, the curtailment shall be automated, \nmeaning that load shall be reduced automatically in response to control signals sent by the PRD \nProvider or its designated agent directly to the control equipment where the load is located \nwithout the requirement for any action by the end-use customer. \n \n \nThreshold Quantity: \n \n \n“Threshold Quantity” shall mean, as to any FRR Entity for any Delivery Year, the sum of (a) the \nUnforced Capacity equivalent (determined using the Pool-Wide Average EFORD through the \n2024/2025 Delivery Year, or pool-wide average Accredited UCAP Factor effective with the \n2025/2026 Delivery Year) of the Installed Reserve Margin for such Delivery Year multiplied by \nthe Preliminary Forecast Peak Load for which such FRR Entity is responsible under its FRR \nCapacity Plan for such Delivery Year, plus (b) the lesser of (i) 3% of the Unforced Capacity \namount determined in (a) above or (ii) 450 MW.  If the FRR Entity is not responsible for all load \nwithin a Zone, the Preliminary Forecast Peak Load for such entity shall be determined in \naccordance with Reliability Assurance Agreement, Schedule 8.1, section D.2. \n \n \nTracking Solar Class:"},{"page":157,"startToken":60999,"endToken":61351,"text":"“Tracking Solar Class” shall mean an ELCC Class consisting of Variable Resources that produce \nelectrical energy with solar panels that are primarily mounted on trackers that align the panels \nwith incoming sunlight over the course of the day. \n \nTransmission Facilities: \n \n \n“Transmission Facilities” shall mean facilities that:  (i) are within the PJM Region; (ii) meet the \ndefinition of transmission facilities pursuant to FERC’s Uniform System of Accounts or have \nbeen classified as transmission facilities in a ruling by FERC addressing such facilities; and (iii) \nhave been demonstrated to the satisfaction of the Office of the Interconnection to be integrated \nwith the PJM Region transmission system and integrated into the planning and operation of the \nPJM Region to serve all of the power and transmission customers within the PJM Region. \n \n \nTransmission Owner: \n \n \n“Transmission Owner” shall mean a Member that owns or leases with rights equivalent to \nownership Transmission Facilities and is a signatory to the PJM Transmission Owners \nAgreement.  Taking transmission service shall not be sufficient to qualify a Member as a \nTransmission Owner. \n \n \nUnforced Capacity: \n \n \n“Unforced Capacity” shall mean installed capacity rated at summer conditions that is not on \naverage experiencing a forced outage or forced derating, calculated for each Capacity Resource \non the 12-month period from October to September without regard to the ownership of or the \ncontractual rights to the capacity of the unit. \n \nUnlimited Resource: \n \n“Unlimited Resource” shall mean a generating unit having the ability to maintain output at a \nstated capability continuously on a daily basis without interruption.  Through the 2024/2025 \nDelivery Year, an Unlimited Resource is a Generation Capacity Resource that is not an ELCC \nResource. \n \nVariable Resource: \n \n“Variable Resource” shall mean a Generation Capacity Resource or a generation Component \nDER within a DER Aggregation Resource that is linked to a DER Capacity Aggregation \nResource, with output that can vary as a function of its energy source, such as wind, solar, run of \nriver hydroelectric power without storage, and landfill gas units without an alternate fuel source.  \nAll Intermittent Resources are Variable Resources, with the exception of Hydropower with Non-\nPumped Storage. \n \n \nWinter Peak Load (or WPL):"},{"page":158,"startToken":61351,"endToken":61718,"text":"“Winter Peak Load” or “WPL” shall mean the average of the Demand Resource customer’s \nspecific peak hourly load between hours ending 7:00 EPT through 21:00 EPT on the PJM \ndefined 5 coincident peak days from December through February two Delivery Years prior the \nDelivery Year for which the registration is submitted.  Notwithstanding, if the average use \nbetween hours ending 7:00 EPT through 21:00 EPT on a winter 5 coincident peak day is below \n35% of the average hours ending 7:00 EPT through 21:00 EPT over all five of such peak days, \nthen up to two such days and corresponding peak demand values may be excluded from the \ncalculation.  Upon approval by the Office of the Interconnection, a Curtailment Service Provider \nmay provide alternative data to calculate Winter Peak Load, as outlined in the PJM Manuals, \nwhen there is insufficient hourly load data for the two Delivery Years prior to the relevant \nDelivery Year or if more than two days meet the exclusion criteria described above. \n \nZonal Capacity Price: \n \n \n“Zonal Capacity Price” shall mean the clearing price required in each Zone to meet the demand \nfor Unforced Capacity and satisfy Locational Deliverability Requirements for the LDA or LDAs \nassociated with such Zone.  If the Zone contains multiple LDAs with different Capacity \nResource Clearing Prices, the Zonal Capacity Price shall be a weighted average of the Capacity \nResource Clearing Prices for such LDAs, weighted by the Unforced Capacity of Capacity \nResources cleared in each such LDA.   \n \n \nZone or Zonal: \n \n \n“Zone” or “Zonal” shall refer to an area within the PJM Region, as set forth in Tariff, \nAttachment J and RAA, Schedule 15, or as such areas may be (i) combined as a result of mergers \nor acquisitions or (ii) added as a result of the expansion of the boundaries of the PJM Region.  A \nZone shall include any Non-Zone Network Load located outside the PJM Region that is served \nfrom such Zone under Tariff, Attachment H-A. \n \nZonal Winter Weather Adjustment Factor (ZWWAF): \n \n“Zonal Winter Weather Adjustment Factor” or “ZWWAF” shall mean the PJM zonal winter \nweather normalized  coincident peak  divided by PJM zonal average of 5 coincident peak loads in \nDecember through February."},{"page":159,"startToken":61718,"endToken":61945,"text":"7.2B \nResponsibility to Pay RBP Charges and Allocation of RBP Shortfall Credits \n \nRBP Charges, which are calculated in accordance with Tariff, Attachment DD, section 18.5(g)(iii) \nand RBP shortfall credits that are collected from RBP Sellers pursuant to Tariff, Attachment DD, \nsection 18.6(d), are allocated to each Electric Distributor zone/area based on the zone/area’s pro \nrata share of the total Final RBP Target.  To the extent an Electric Distributor has notified the \nOffice of the Interconnection of RBP Obligation (“RBO”) MW for each Load Serving Entity in its \nzone/area, as set forth in Tariff, Attachment DD, section 18.3, the Office of the Interconnection \nshall further allocate the RBP Charges, and any RBP shortfall credits, for that zone/area to each \nParty to the RAA, i.e. each Load Serving Entity, in the Electric Distributor’s zone/area in \naccordance with the Electric Distributor’s notification. \n \nTo the extent an Electric Distributor has not notified the Office of the Interconnection of the RBO \nMW of each Load Serving Entity in its zone(s)/area(s), the Office of the Interconnection shall \nfurther allocate the RBP Charges and RBP shortfall charges for that zone/area to each Load \nServing Entity in the zone/area based on each Load Serving Entity’s share of the Daily Unforced \nCapacity Obligation MW in the zone/area."},{"page":160,"startToken":61945,"endToken":62021,"text":"7.2C  Provision of RBP Obligations  \n \nDuring the Delivery Year, no later than 36 hours prior to the start of each Operating Day, \nthe Electric Distributor shall provide to PJM, for each Party to this Agreement serving load in such \nElectric Distributor's zone/area, any RBP Obligation (“RBO”) MW.  The Electric Distributor may \nsubmit corrections to the RBO MW data up to 12:00PM Eastern Prevailing Time of the next \nBusiness Day following the Operating Day."},{"page":161,"startToken":62021,"endToken":62633,"text":"D. \nFRR Capacity Plans \n \n1. \nEach FRR Entity shall submit its initial FRR Capacity Plan as required by subsection C.1 \nof this Schedule, and shall annually extend and update such plan by no later than one month prior \nto the Base Residual Auction for each succeeding Delivery Year in such plan.  Each FRR \nCapacity Plan shall indicate the nature and current status of each resource, including the status of \neach Planned Generation Capacity Resource or Planned Demand Resource, the planned \ndeactivation or retirement of any Generation Capacity Resource or Demand Resource, and the \nstatus of commitments for each sale or purchase of capacity included in such plan. \n \n1.1 \nBeginning with the 2020/2021 Delivery Year and for all subsequent Delivery Years, the \nFRR Capacity Plan shall comprise only Capacity Performance Resources and Seasonal Capacity \nPerformance Resources.  An FRR Entity may not use an Existing Generation Capacity Resource \nnot owned by such FRR Entity as of June 1, 2027 or any resource committed through the \nReliability Backstop Procurement to satisfy its Capacity FRR Plan. \n \n2. \nThe FRR Capacity Plan of each FRR Entity that commits that it will not sell surplus \nCapacity Resources as a Capacity Market Seller in any auction conducted under Attachment DD \nof the PJM Tariff, or to any direct or indirect purchaser that uses such resource as the basis of \nany Sell Offer in such auction, shall designate Capacity Resources in a megawatt quantity no less \nthan the Forecast Pool Requirement for each applicable Delivery Year times the FRR Entity’s \nallocated share of the Preliminary Zonal Peak Load Forecast for such Delivery Year, as \ndetermined in accordance with procedures set forth in the PJM Manuals.  If the FRR Entity is not \nresponsible for all load within a Zone, the Preliminary Forecast Peak Load for such entity shall \nbe the Base Zonal FRR Scaling Factor times the summation of the FRR Entity’s MW share of \nthe Zonal Weather Normalized Summer Peak last determined prior to the Base Residual Auction \nfor such Delivery Year plus the Obligation Peak Load MW associated with any Load Adjustment \nspecified for such Delivery Year for any “zone/area” served by the FRR Entity’s Capacity Plan.  \nThe Obligation Peak Load MW associated with a Load Adjustment specified for a “zonal/area” \nis determined as set forth in RAA, Schedule 8, section B. \n \nThe FRR Capacity Plan of each FRR Entity that does not commit that it will not sell surplus \nCapacity Resources as set forth above shall designate Capacity Resources at least equal to the \nThreshold Quantity.  To the extent the FRR Entity’s allocated share of the Final Zonal Peak \nLoad Forecast exceeds the FRR Entity’s allocated share of the Preliminary Zonal Peak Load \nForecast, such FRR Entity’s FRR Capacity Plan shall be updated to designate additional \nCapacity Resources in an amount no less than the Forecast Pool Requirement times such \nincrease; provided, however, any excess megawatts of Capacity Resources included in such FRR \nEntity’s previously designated Threshold Quantity, if any, may be used to satisfy the capacity \nobligation for such increased load.  To the extent the FRR Entity’s allocated share of the Final \nZonal Peak Load Forecast is less than the FRR Entity’s allocated share of the Preliminary Zonal \nPeak Load Forecast, such FRR Entity’s FRR Capacity Plan may be updated to release previously \ndesignated Capacity Resources in an amount no greater than the Forecast Pool Requirement \ntimes such decrease.  Peak load values referenced in this section shall be adjusted as necessary to \ntake into account any applicable Nominal PRD Values approved pursuant to Schedule 6.1 of this \nAgreement.  Any FRR Entity seeking an adjustment to peak load for Price Responsive Demand"},{"page":162,"startToken":62633,"endToken":63216,"text":"must submit a separate PRD Plan in compliance with Section 6.1 (provided that the FRR Entity \nshall not specify any PRD Reservation Price), and shall register all PRD-eligible load needed to \nsatisfy its PRD commitment and be subject to compliance charges as set forth in that Schedule \nunder the circumstances specified therein; provided that for non-compliance by an FRR Entity, \nthe compliance charge rate shall be equal to 1.20 times the Capacity Resource Clearing Price \nresulting from all RPM Auctions for such Delivery Year for the LDA encompassing the FRR \nEntity’s Zone, weight-averaged for the Delivery Year based on the prices established and \nquantities cleared in the RPM auctions for such Delivery Year; and provided further that an \nalternative PRD Provider may provide PRD in an FRR Service Area by agreement with the FRR \nEntity responsible for the load in such FRR Service Area, subject to the same terms and \nconditions as if the FRR Entity had provided the PRD. \n \n3. \nAs to any FRR Entity, the Base Zonal FRR Scaling Factor for each Zone in which it \nserves load for a Delivery Year shall equal [(ZPLDY-ZLA) / ZWNSP], where: \n \nZPLDY = Preliminary Zonal Peak Load Forecast for such Zone for such Delivery Year;  \n \nZLA = the Zonal MW quantity of Load Adjustment for such Delivery Year; and  \n \nZWNSP = Zonal Weather-Normalized Summer Peak Load for such Zone for the summer \nconcluding four years prior to the commencement of such Delivery Year. \n \n4. \nCapacity Resources identified and committed in an FRR Capacity Plan shall meet all \nrequirements under this Agreement, the PJM Tariff, and the PJM Operating Agreement \napplicable to Capacity Resources, including, as applicable, requirements and milestones for \nPlanned Generation Capacity Resources and Planned Demand Resources.  A Capacity Resource \nsubmitted in an FRR Capacity Plan must be on a unit-specific basis, and may not include “slice \nof system” or similar agreements that are not unit specific.  An FRR Capacity Plan may include \nbilateral transactions that commit capacity for less than a full Delivery Year only if the resources \nincluded in such plan in the aggregate satisfy all obligations for all Delivery Years.  All demand \nresponse, load management, energy efficiency, or similar programs on which such FRR Entity \nintends to rely for a Delivery Year must be included in the FRR Capacity Plan, subject to \napplicable demand resource constraints for the relevant Delivery Year, submitted three years in \nadvance of such Delivery Year and must satisfy all requirements applicable to Demand \nResources or Energy Efficiency Resources, as applicable, including, without limitation, those set \nforth in Schedule 6 to this Agreement and the PJM Manuals; provided, however, that previously \nuncommitted Unforced Capacity from such programs may be used to satisfy any increased \ncapacity obligation for such FRR Entity resulting from a Final Zonal Peak Load Forecast \napplicable to such FRR Entity.  Without limiting the generality of the foregoing, the FRR Entity \nmust submit a Demand Resource Sell Offer Plan 15 business days before the deadline for \nsubmitting an FRR Capacity Plan as to any Demand Resources it intends to include in such FRR \nCapacity Plan and may only include in such FRR Capacity Plan Demand Resources that are \napproved by PJM following review of such Demand Resource Sell Offer Plan.  The \nrequirements, standards, and procedures for a Demand Resource Sell Offer Plan shall be as set \nforth in Schedule 6 of this Agreement, provided that all references (including deadlines) in \nSchedule 6, section A-1 to submission or clearing of a Demand Resource offer in an RPM"},{"page":163,"startToken":63216,"endToken":63818,"text":"Auction shall be understood for purposes of FRR Entities as referring to inclusion of a Demand \nResource in an FRR Capacity Plan, and a distinct Demand Resource Officer Certification Form \nshall be applicable to FRR Entities, as shown in the PJM Manuals and provided on the PJM \nwebsite. \n \n5. \nFor each LDA for which the Office of the Interconnection is required to establish a \nseparate Variable Resource Requirement Curve for any Delivery Year addressed by such FRR \nCapacity Plan, the plan must include a Percentage Internal Resources Required, subject to \nsubsections D.1.1 and D.2 of this Schedule.  The Percentage Internal Resources Required will be \ncalculated as the LDA Reliability Requirement less the CETL for the Delivery Year, as \ndetermined by the RTEP process as set forth in the PJM Manuals.  Such requirement shall be \nexpressed as a percentage of the Unforced Capacity Obligation based on the Preliminary Zonal \nPeak Load Forecast multiplied by the Forecast Pool Requirement.  Notwithstanding the \nprovisions of Sections C.1 and C.2 of this Schedule 8.1, an FRR Entity may terminate its \nelection of the FRR Alternative prior to meeting its minimum five year commitment \nwithout penalty for any Delivery Year after the first Delivery Year of its minimum five \nyear FRR commitment for which the Office of the Interconnection will be required to \nestablish a separate Variable Resource Requirement Curve by giving written notice two \nmonths prior to the Base Residual Auction for the Delivery Year. The Office of the \nInterconnection shall be deemed to be required to establish a separate Variable Resource \nRequirement Curve for an LDA if the LDA is the Eastern Mid-Atlantic Region \n(“EMAR”), Southwest Mid-Atlantic Region (“SWMAR”), or Mid-Atlantic Region \n(“MAR”), or for other LDAs if the separate modeling is required by Section \n5.10(a)(ii)(A) or (B) of Attachment DD of the Tariff. \n \n6. \nAn FRR Entity may reduce the Percentage Internal Resources Required as to any LDA to \nthe extent the FRR Entity commits to a transmission upgrade that increases the CETL for such \nLDA.  Any such transmission upgrade shall adhere to all requirements for a Qualified \nTransmission Upgrade as set forth in Attachment DD to the PJM Tariff.  The increase in CETL \nused in the FRR Capacity Plan shall be that approved by PJM prior to inclusion of any such \nupgrade in an FRR Capacity Plan.  The FRR Entity shall designate specific additional Capacity \nResources located in the LDA from which the CETL was increased, to the extent of such \nincrease. \n \n7. \nThe Office of the Interconnection will review the adequacy of all submittals hereunder \nboth as to timing and content.  A Party that seeks to elect the FRR Alternative that submits an \nFRR Capacity Plan which, upon review by the Office of the Interconnection, is determined not to \nsatisfy such Party’s capacity obligations hereunder, shall not be permitted to elect the FRR \nAlternative.  If a previously approved FRR Entity submits an FRR Capacity Plan that, upon \nreview by the Office of the Interconnection, is determined not to satisfy such Party’s capacity \nobligations hereunder, the Office of the Interconnection shall notify the FRR Entity, in writing, \nof the insufficiency within five (5) business days after the submittal deadline of the FRR \nCapacity Plan.  Through the 2024/2025 Delivery Year, if the FRR Entity does not cure such \ninsufficiency within five (5) business days after receiving such notice of insufficiency, then such \nFRR Entity shall be assessed an FRR Commitment Insufficiency Charge, in an amount equal to \ntwo times the Cost of New Entry for the relevant location, in $/MW-day, times the shortfall of"},{"page":164,"startToken":63818,"endToken":64389,"text":"Capacity Resources below the FRR Entity’s capacity obligation (including any Threshold \nQuantity requirement) in such FRR Capacity Plan, for the remaining term of such plan. For \nDelivery Years between the 2025/2026 Delivery Year through the 2028/2029 Delivery Year, no \nFRR Commitment Insufficiency Charge shall be assessed. Effective with the 2029/2030 Delivery \nYear and subsequent Delivery Years, if the FRR Entity does not cure such insufficiency within \nfive (5) business days after receiving such notice of insufficiency, then such FRR Entity shall be \nassessed an FRR Commitment Insufficiency Charge, in an amount equal to the price level \ncorresponding to point (1) of the Variable Resource Requirement curve, as provided in Tariff, \nAttachment DD, section 5.10(a)(i), for the relevant Locational Deliverability Area, in $/MW-\nday, times the shortfall of Capacity Resources below the FRR Entity’s capacity obligation \n(including any Threshold Quantity requirement) in such FRR Capacity Plan, for such Delivery \nYear.  \n \n8. \nIn a state regulatory jurisdiction that has implemented retail choice, the FRR Entity must \ninclude in its FRR Capacity Plan all load, including expected load growth, in the FRR Service \nArea, notwithstanding the loss of any such load to or among alternative retail LSEs.  In the case \nof load reflected in the FRR Capacity Plan that switches to an alternative retail LSE, where the \nstate regulatory jurisdiction requires switching customers or the LSE to compensate the FRR \nEntity for its FRR capacity obligations, such state compensation mechanism will prevail.  In the \nabsence of a state compensation mechanism, the applicable alternative retail LSE shall \ncompensate the FRR Entity at the capacity price in the unconstrained portions of the PJM \nRegion, as determined in accordance with Attachment DD to the PJM Tariff, provided that the \nFRR Entity may, at any time, make a filing with FERC under Sections 205 of the Federal Power \nAct proposing to change the basis for compensation to a method based on the FRR Entity's cost \nor such other basis shown to be just and reasonable, and a retail LSE may at any time exercise its \nrights under Section 206 of the FPA. \n \n9. \nNotwithstanding the foregoing, in lieu of providing the compensation described above, \nsuch alternative retail LSE may, for any Delivery Year subsequent to those addressed in the FRR \nEntity’s then-current FRR Capacity Plan, provide to the FRR Entity Capacity Resources \nsufficient to meet the capacity obligation described in paragraph D.2 for the switched load. Such \nCapacity Resources shall meet all requirements applicable to Capacity Resources pursuant to this \nAgreement, the PJM Tariff, and the PJM Operating Agreement, all requirements applicable to \nresources committed to an FRR Capacity Plan under this Agreement, and shall be committed to \nservice to the switched load under the FRR Capacity Plan of such FRR Entity.  The alternative \nretail LSE shall provide the FRR Entity all information needed to fulfill these requirements and \npermit the resource to be included in the FRR Capacity Plan.  The alternative retail LSE, rather \nthan the FRR Entity, shall be responsible for any performance charges or compliance penalties \nrelated to the performance of the resources committed by such LSE to the switched load.  For \nany Delivery Year, or portion thereof, the foregoing obligations apply to the alternative retail \nLSE serving the load during such time period.  PJM shall manage the transfer accounting \nassociated with such compensation and shall administer the collection and payment of amounts \npursuant to the compensation mechanism."},{"page":165,"startToken":64389,"endToken":64428,"text":"Such load shall remain under the FRR Capacity Plan until the effective date of any termination \nof the FRR Alternative and, for such period, shall not be subject to Locational Reliability \nCharges under Section 7.2 of this Agreement."}],"sections":[{"p":1,"at":0,"title":"Attachment B","method":"printed heading","endPage":18,"endAt":466,"startToken":0,"endToken":5630},{"p":18,"at":466,"title":"Attachment K-Appendix, section 1.4B.","method":"printed heading","endPage":21,"endAt":401,"startToken":5630,"endToken":6298},{"p":21,"at":401,"title":"Attachment K-Appendix, section 1.5A, to participate in the PJM Interchange Energy Market","method":"printed heading","endPage":58,"endAt":959,"startToken":6298,"endToken":18977},{"p":58,"at":959,"title":"Attachment K-Appendix, section 6.6(c) or the defaults below:","method":"printed heading","endPage":65,"endAt":2270,"startToken":18977,"endToken":21802},{"p":65,"at":2270,"title":"A. The Capacity Market Seller shall provide to the Office of the","method":"printed heading","endPage":65,"endAt":2851,"startToken":21802,"endToken":21888},{"p":65,"at":2851,"title":"B. The Office of the Interconnection and the Market Monitoring Unit shall","method":"printed heading","endPage":93,"endAt":1878,"startToken":21888,"endToken":36063},{"p":93,"at":1878,"title":"A. It has a documented plan in place to retire the resource prior to or during the Delivery","method":"printed heading","endPage":93,"endAt":2465,"startToken":36063,"endToken":36160},{"p":93,"at":2465,"title":"B. Significant physical operational restrictions cause long term or permanent changes to the","method":"printed heading","endPage":93,"endAt":2795,"startToken":36160,"endToken":36209},{"p":93,"at":2795,"title":"C. The Capacity Market Seller is involved in an ongoing regulatory proceeding (e.g. –","method":"printed heading","endPage":161,"endAt":0,"startToken":36209,"endToken":62021},{"p":161,"at":0,"title":"D. FRR Capacity Plans","method":"printed heading","endPage":165,"endAt":233,"startToken":62021,"endToken":64428}]}