{"document":{"slug":"attachment-er27-454-b","title":"Attachment B- Clean Tariff Revisions","issued":"2026-11-09","accession":"20261109-5216","docket":"ER27-454-000","group":"PJM Reliability Backstop Procurement","filer":"PJM","kind":"attachment","file":"sources/originals/attachment-er27-454-b.pdf","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20261109-5216","parent":"refiling-er27-454-pjm-backstop","sha256":"e9866f181a49cc3f35b35f144e772210af9a4c02fbefc9dc5fe5d3c95d6bae96","pages":66,"tokens":24243,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":9,"text":"Attachment B \n \n \nRevisions to the Tariff \n(in clean format)"},{"page":2,"startToken":9,"endToken":392,"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":3,"startToken":392,"endToken":733,"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":4,"startToken":733,"endToken":1015,"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":5,"startToken":1015,"endToken":1288,"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":6,"startToken":1288,"endToken":1702,"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":7,"startToken":1702,"endToken":2042,"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":8,"startToken":2042,"endToken":2479,"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":9,"startToken":2479,"endToken":2805,"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":10,"startToken":2805,"endToken":3124,"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":11,"startToken":3124,"endToken":3397,"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":12,"startToken":3397,"endToken":3663,"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":13,"startToken":3663,"endToken":4009,"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":14,"startToken":4009,"endToken":4530,"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":15,"startToken":4530,"endToken":4933,"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":16,"startToken":4933,"endToken":5261,"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 for the 2028/2029 or earlier Delivery Year as of the commencement of the Reliability \nBackstop Procurement (except for capacity that is first committed in the Third Incremental \nAuction associated with the 2027/2028 Delivery Year), (ii) is supplied by eligible Capacity \nResources in accordance with Tariff, Attachment DD, section 18.2(b), and (iii) is supported by \nevidence, 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":17,"startToken":5261,"endToken":5537,"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 any one of:(1) a cash deposit, including any interest thereon, (2) a \nsurety bond with a provider, amount and form determined by and acceptable to PJM or \nPJMSettlement, or (3) a letter of credit issued for the benefit of PJM or PJMSettlement, with a \nprovider, amount and form determined 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":18,"startToken":5537,"endToken":5793,"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:"},{"page":19,"startToken":5793,"endToken":6159,"text":"“Real-time Settlement Interval” shall mean the interval used by settlements, which shall be every \nfive minutes. \nReal-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."},{"page":20,"startToken":6159,"endToken":6460,"text":"Regional Entity: \n \n“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":21,"startToken":6460,"endToken":6849,"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."},{"page":22,"startToken":6849,"endToken":7220,"text":"Reserve Sub-zone: \n \n“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":23,"startToken":7220,"endToken":7510,"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:"},{"page":24,"startToken":7510,"endToken":7927,"text":"“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, \nelectric 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."},{"page":25,"startToken":7927,"endToken":8228,"text":"Self-Supply Seller: \n \n“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."},{"page":26,"startToken":8228,"endToken":8543,"text":"Small Commercial Customer: \n \n“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"},{"page":27,"startToken":8543,"endToken":8926,"text":"Agreement, Schedule 1, section 2, and the parallel provisions of Tariff, Attachment K-Appendix, \nsection 2. \n \nStart 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."},{"page":28,"startToken":8926,"endToken":9337,"text":"State Commission: \n \n“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"},{"page":29,"startToken":9337,"endToken":9874,"text":"another 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 \nhaving 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:"},{"page":30,"startToken":9874,"endToken":10200,"text":"“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 \noperation, 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:"},{"page":31,"startToken":10200,"endToken":10528,"text":"“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: \n \n“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:"},{"page":32,"startToken":10528,"endToken":10789,"text":"“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 \nInterconnection 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":33,"startToken":10789,"endToken":11189,"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 Reliability Pricing Model Auction and is not required to submit a binding notice \nof intent to offer into such auction.  However, a Planned Generation Capacity Resource that is \ncommitted in the RBP for the 2030/2031 Delivery Year must still be the subject of a notice of \nintent to be offered into the Base Residual Auction associated with the 2030/2031 Delivery Year. \nIn the event a committed RBP Resource is not expected to be in-service or deliverable by the \nrelevant Delivery Year, the Capacity Market Seller of such committed RBP Resource may notify \nthe Office of the Interconnection, with supporting documentation, that the resource is not expected \nto be in-service or deliverable by the relevant Delivery Year. Such notice for a committed RBP \nResource shall be submitted no later than (i) the immediately preceding December 1 for a Base \nResidual Auction or (ii) ninety (90) days prior to the commencement of the offer period for an \nIncremental Auction. A committed RBP Resource that provides such notice will be assessed any \napplicable RBP shortfall charge and not be allowed to be offered into the applicable RPM Auction."},{"page":34,"startToken":11189,"endToken":11818,"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":35,"startToken":11818,"endToken":12393,"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":36,"startToken":12393,"endToken":12908,"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":37,"startToken":12908,"endToken":13518,"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":38,"startToken":13518,"endToken":14125,"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":39,"startToken":14125,"endToken":14758,"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":40,"startToken":14758,"endToken":15359,"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":41,"startToken":15359,"endToken":15807,"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 Reliability Pricing Model Auctions beginning with the first Delivery Year in which an RBP \nResource has been committed through the Reliability Backstop Procurement and is expected to \nbe in-service.  Such offer requirement shall continue for each subsequent Delivery Year through \nthe end of the fixed 15-year term, except RBP UCAP MW for RBP Resources without a notice \nof intent to offer submitted pursuant to Tariff, Attachment DD, section 5.5 for the 2030/2031 \nBase Residual Auction, which shall have a must offer requirement beginning in the next \napplicable RPM Auction, including but not limited to the 2031/2032 Base Residual Auction and \nthe 2029/2030 Second Incremental Auction to the extent such resource has RBP UCAP MW \ncommitted and is expected to be in-service for those Delivery Years."},{"page":42,"startToken":15807,"endToken":16377,"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":43,"startToken":16377,"endToken":16941,"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 Auctions shall be the Reliability \nPricing Model Auctions beginning with the first Delivery Year in which an RBP Resource has \nbeen committed through the Reliability Backstop Procurement and is expected to be in-service.  \nSuch offer requirement shall continue for each subsequent Delivery Year through the end of the \nfixed 15-year term, except RBP UCAP MW for Capacity Performance Resources without a \nnotice of intent to offer submitted pursuant to Tariff, Attachment DD, section 5.5 for the \n2030/2031 Base Residual Auction, which shall have a must offer requirement beginning in the \nnext applicable RPM Auction, including but not limited to the 2031/2032 Base Residual Auction \nand the 2029/2030 Second Incremental Auction to the extent such resource has an RBP UCAP \nMW commitment and is expected to be in-service for those Delivery Years."},{"page":44,"startToken":16941,"endToken":16984,"text":"18.  \nRELIABILITY BACKSTOP PROCUREMENT \n \nThe Reliability Backstop Procurement or “RBP” is a one-time procurement, starting in 2027, 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":45,"startToken":16984,"endToken":17457,"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 lesser of the (1) most up \nto date UCAP MW quantity that PJM cleared short of the PJM Region Reliability Requirement \nfor the 2028/2029 Delivery Year Base Residual Auction or (2) the UCAP equivalent of the \naggregate region-wide Large Load MW quantity reported by the Electric Distributor in accordance \nwith Tariff, Attachment DD, section 18.3A.  Specifically, the Initial RBP Target shall equal the \nlesser of ([the latest estimate of the PJM Region Reliability Requirement for the 2028/2029 \nDelivery Year, calculated as the RTO Region Peak Load Forecast for the 2028/2029 Delivery Year \nfrom the 2027 Load Forecast times the 2028/2029 Forecast Pool Requirement from the updated \nplanning parameters available at the commencement of the RBP, less the sum of all updated \nUnforced Capacity Obligations of FRR Entities in the PJM Region] minus [the UCAP-equivalent \nof the ICAP quantity of Capacity Resources that cleared in the 2028/2029 Base Residual Auction \nusing the latest capacity accreditation factors for the 2028/2029 Delivery Year available at the \ncommencement of the RBP], the aggregate region-wide Large Load MW reported by the Electric \nDistributor in accordance with Tariff, Attachment DD, section 18.3A times the most recent \n2028/2029 Forecast Pool Requirement).  \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, if \nrequested by an Electric Distributor, and accompanied by an officer attestation in accordance with \nthe PJM Manuals, by up to the associated MW quantity of load that participates in a peak shaving \nadjustment program for a minimum period of five years where such Electric Distributor’s \nzone/area addresses their capacity needs through peak shaving adjustment programs that are \ncodified in state law and that also meet the requirements of Tariff, Attachment DD-2."},{"page":46,"startToken":17457,"endToken":17999,"text":"18.2 \nQualifying RBP Offset UCAP MW   \n \n(a) \nQualifying RBP Offset UCAP MW is capacity that will be located within the PJM \nRegion (i) has not previously supported a capacity commitment or been committed in an FRR Plan \nfor the 2028/2029 or earlier Delivery Year as of the commencement of the Reliability Backstop \nProcurement (except for capacity that is first committed in the Third Incremental Auction \nassociated with the 2027/2028 Delivery Year); and (ii) is supplied by a resource that satisfies each \nof the criteria 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 , and must meet the requirements of being \neligible to be an RBP Resource as set forth in Tariff, Attachment DD, section 18.5(c) and 18.5(d), \nexcept that the associated participation contract(s) are not required to be eligible for the offset. \n. \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 that is the subject of a bilateral \nagreement with a Large Load, up to the capacity obligation of the Large Load, reported to the \nOffice of the Interconnection in accordance with Tariff, Attachment DD, section 18.3(a)(2) in their \nrespective zones/areas.  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"},{"page":47,"startToken":17999,"endToken":18379,"text":"Delivery Year, and matched with Large Load that has an executed electric service \nagreement or transmission service agreement, indicating that the load will be coming online \nin the 2027/2028 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 \nassociated 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 Large Load will be coming online in the 2027/2028 or 2028/2029 \nDelivery Year; 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 Large Load(s) will, in a MW quantity equal to \nMW quantity of the new load(s), either (a) participate as Annual Demand Resources or \nDER Capacity 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 most up-to-date ELCC Class Ratings associated with \nthe 2028/2029 Delivery Year, or the estimated unit-specific UCAP value for resources with no \nELCC Class Rating available at the commencement of the RBP. \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 by the aggregate MW quantity of Large Load reported by each Electric \nDistributor, as reported in accordance with Tariff, Attachment DD, section 18.3(a)(2), and the total \nMW quantity that is subject to the RBP opt-out, as requested in accordance with Tariff, Attachment \nDD, section 18.1(d), for the relevant zone/area."},{"page":48,"startToken":18379,"endToken":18792,"text":"18.3 \n Allocation of RBP Charges, Credits, and Shortfall Charges \n \n(a) \nAllocation of RBP Charges to Electric Distributor zone/area \n \n(i)  The 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 total incremental Large Load \nreported to the Office of the Interconnection in accordance with Tariff, Attachment DD, section \n18.3A.  Such allocation shall be only to Electric Distributors’ zone/area not located in an FRR \nService Area and based on information provided by each such Electric Distributor.     \n \n \n \n(ii)  The allocation based on the zone/area’s MW share of the total incremental Large Load MW \nshall be reduced for the purpose of this calculation to the extent:  \n \n(1) \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(2) \nan Electric Distributor zone/area meets the opt-out provisions set forth in \naccordance with Tariff, Attachment DD, section 18.1(d). \n \nThe resulting reduced MW, floored at zero, shall be used to calculate the zone/area’s assigned pro-\nrata share of the Final RBP Target MW.  The zone/area’s assigned share of the Final RBP Target \nMW shall remain constant throughout the fixed, 15-year term. \n \n(iii)  The 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) \nAllocation of RBP Charges to Load Serving Entities \n \nLSEs located in an Electric Distributor zone/area with a positive, non-zero allocation of \nRBP Charges pursuant to Tariff, Attachment DD, section 18.3(a)(iii) shall be eligible to be \nallocated responsibility for RBP Charges as follows: \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."},{"page":49,"startToken":18792,"endToken":18988,"text":"(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 one hundred and twenty \n(120) days prior to the 2028/2029 Delivery Year.  Electric Distributors may report updated \nRBO MW to the Office of the Interconnection after the initial allocation is reported to \nreflect any changes in Load Serving Entities that should be assigned RBP Charges.  If no \nRBO MW are reported to the Office of the Interconnection for an Electric Distributor \nzone/area, PJM will allocate the RBP Charges for that zone/area to all load in the zone/area \nusing each LSE’s ratio share of the Daily Unforced Capacity Obligation for the zone/area \nas determined in RAA, Schedule 8. PJMSettlement shall be the Counterparty to each LSE’s \nobligation to pay, and payments of, 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, Article 7, section 7.2B."},{"page":50,"startToken":18988,"endToken":19138,"text":"18.3A Electric Distributor Reporting Requirement for Reliability Backstop Procurement \n \nNo later than seven days prior to the commencement of the Reliability Backstop Procurement, each \nElectric Distributor outside of an FRR Service Area shall report to the Office of the Interconnection \nthe quantity and identity of incremental Large Load that is supported by an electric service \nobligation, construction commitment, or similar agreement.  Such Electric Distributor shall also \nreport the amount (in MW) that represents the difference between the aggregate quantity of Large \nLoad based on the 2026 actual summer peak and the expected summer peak of Large Load for the \n2028/2029 Delivery Year.  An Electric Distributor shall provide an explanation for any deviation \nbetween the expected quantity of Large Loads for the 2028/2029 Delivery Year and the values \nprovided by the Electric Distributor to the Office of the Interconnection as part of the development \nfor the load forecast."},{"page":51,"startToken":19138,"endToken":19393,"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 four weeks.  The clearing and selection process will \ntake place thereafter and concluding six weeks following the close of the offer submission window.  \nThe Office of the Interconnection shall notify RBP Sellers that receive a commitment as an RBP \nResource as soon as practicable upon the conclusion of the RBP.  The Office of the Interconnection \nshall post specific dates on the PJM website prior to the commencement of the Reliability Backstop \nProcurement.     \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":52,"startToken":19393,"endToken":19793,"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 \nfor the 2028/2029 or earlier Delivery Year as of the commencement of the Reliability \nBackstop Procurement (except for capacity that is first committed in the Third Incremental \nAuction associated with the 2027/2028 Delivery Year); \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; and \n \n(v) \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 \ngeneration resource that had deactivated, or announced deactivation, on or before April 10, \n2026."},{"page":53,"startToken":19793,"endToken":20187,"text":"(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 the 2026/2027 Delivery Year \nunless such location represents an incremental increase in capacity resulting from an \ninvestment in new generation 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(a) 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; \n \n(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;"},{"page":54,"startToken":20187,"endToken":20531,"text":"(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, the Office \nof the Interconnection shall complete the Reliability Backstop Procurement in two stages: (1) \ngating criteria evaluation and (2) selection assessment, with notification of finalized commitments \nposted prior to the Base Residual Auction for the 2030/2031 Delivery Year. The Reliability \nBackstop 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 \nof being notified by PJM.  \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 \nstudy, the project must provide study information and timeline from (1) an \nindependent consultant report or (2) the most current PJM study;"},{"page":55,"startToken":20531,"endToken":20923,"text":"(2) \nFor projects that are not the subject of a completed interconnection \nstudy or are not currently under study as part of an active New Service Request by \nthe Office of the Interconnection, evidence of 100% Site Control consistent with \nTariff, Part VIII, Subpart A, section 402 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 RBP Sell Offer. \n \nSuch projects must also be accompanied by a certification, executed by an \nofficer or authorized representative of the Generation Project Developer, verifying \nthat the Site Control requirements have been met. Further, at Transmission \nProvider’s request, Generation Project Developer shall provide copies of landowner \nattestations or county recordings. The Site Control requirements include an acreage \nrequirement for the Project, as set forth in the PJM Manuals. \n \n \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":56,"startToken":20923,"endToken":21251,"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":57,"startToken":21251,"endToken":21653,"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":58,"startToken":21653,"endToken":21710,"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":59,"startToken":21710,"endToken":22127,"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 beginning with the first Delivery Year in which such resource \nis has an RBP commitment and is expected to be in service. Such offer requirement shall continue \nfor each subsequent Delivery Year through the end of the RBP term, except RBP UCAP MW for \nRBP Resources that is expected to be in service for the 2030/2031 Delivery Year without a notice \nof intent to offer submitted pursuant to Tariff, Attachment DD, section 5.5 for the 2030/2031 Base \nResidual Auction shall have a must offer requirement in the next RPM Auction, including but not \nlimited to the 2031/2032 Base Residual Auction and the 2030/2031 First 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"},{"page":60,"startToken":22127,"endToken":22512,"text":"RBP 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 \nof 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":61,"startToken":22512,"endToken":22623,"text":"18.7 \nExiting Load Serving Entity RBP Obligations \n \n \nIn the event a Load Serving Entity that is allocated RBP Charges withdraws from PJM (whether \nor not caused by the physical withdrawal of another entity from the PJM Region), such Load \nServing Entity shall be responsible for the remainder of the RBP Charges allocated to it, subject \nto a rate filing with the Federal Energy Regulatory Commission that details the specific terms and \namounts owed.  Nothing in this provision shall limit such Load Serving Entity’s ability to seek \nredress from another entity to the extent the Load Serving Entity’s withdrawal is caused by that \nother entity’s physical withdrawal from the PJM Region."},{"page":62,"startToken":22623,"endToken":23019,"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.   \n \nSettlement during any Delivery Year of cleared positions resulting from, or expected to result \nfrom, the Reliability Backstop Procurement, including payments and Locational Reliability \nCharges associated with the capacity commitments of RBP Resources, shall not be considered in \nPeak Market Activity pursuant to Tariff, Attachment Q, Section VII.A.  The forms of acceptable \ncredit support 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 RBP credit \nrequirement 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":63,"startToken":23019,"endToken":23366,"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 days 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 RBP credit \nrequirement after a one-year look-back from the achievement of commercial \noperation.    \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$\n𝑀𝑊𝑑𝑎𝑦\n) \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":64,"startToken":23366,"endToken":23745,"text":"(A) \nThe cumulative RBP credit requirement for Load Serving Entities for a \ngiven Delivery Year shall be equivalent to RBP Credit Rate (as determined in accordance \nwith Tariff, Attachment DD, section 18.8(b)(i)(B)) multiplied by the committed RBP \nUCAP MW amount, where the committed RBP UCAP MW amount shall equal the total \namount of RBP UCAP MW that receives a commitment through the Reliability Backstop \nProcurement and is supported by an RBP Resource that has reached commercial operation \nby the start of the applicable Delivery Year.  The foregoing determination of the committed \nRBP UCAP MW amount shall exclude each commitment of RBP UCAP MW that is \nrescinded pursuant to Tariff, Attachment DD, section 18.6(e).   \n \nFollowing the commencement of commercial operation of all Capacity Resources with \nRBP commitments, PJM shall review the RBP Credit Rate and present any \nrecommendations to stakeholders through the Members Committee.  \n \nWhen total posted RBP Collateral is greater than the total remaining RBP payment \nobligations, the Office of the Interconnection will make available excess collateral, upon \nrequest by an applicable Load Serving Entity.   \n \nThe cumulative RBP credit requirement for Load Serving Entities shall be met \nthrough RBP Collateral posted by those Load Serving Entities allocated cost pursuant to \nTariff, Attachment DD, section 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, and each such LSE \nshall maintain credit support in an amount equal to its RBP LSE Credit \nRequirement, calculated as follows: \n \nRBP LSE Credit Requirement = RBP Credit Rate x Allocated RBP Credit \nMW \n \nFor purposes of this calculation: \n \nRBP Credit Rate shall mean an amount per MW equal to 40% of the \ndiscounted total RBP payment obligation per MW over the applicable RBP \ncommitment term, calculated using the weighted-average RBP clearing price of all \nRBP UCAP MW committed through the RBP.   \n \nAllocated RBP Credit MW shall mean the amount of RBP UCAP MW, \nexpressed in MW, for which the LSE has been allocated responsibility for RBP \nCharges in accordance with Tariff, Attachment DD, section 18.3 and as determined \nin accordance with this Tariff, Attachment DD, section 18.8(b)(i)(B)(1) or (2), as \nappropriate."},{"page":65,"startToken":23745,"endToken":24196,"text":"(1) \nFor Load Serving Entities with an RBP Obligation in accordance Tariff, \nAttachment DD, section 18.3, prior to forty-five (45) days before the start of a \ngiven Delivery Year, such Load Serving Entities, must post, or maintain an \nexisting, RBP Collateral equal to the RBP Credit Rate multiplied by the Allocated \nRBP Credit MW, where the zone/area allocated amount committed RBP UCAP \nMW is further allocated to each Load Serving Entity based on the relevant Load \nServing Entity’s percent share of the zone/area’s RBP Obligation MW assigned \nby the Electric Distributor.  For Load Serving Entities required to post RBP \nCollateral by this section 18.8(b)(i)(B)(1), the Office of the Interconnection may \nevaluate such Load Serving Entity for unreasonable credit risk under the \nUnreasonable Credit Risk provisions of Tariff, Attachment Q, Section II, and \nrequire additional RBP Collateral as appropriate.   \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 a given Delivery Year, such Load Serving \nEntities, may be required to post, or maintain an existing, RBP Collateral \nequal to the RBP Credit Rate multiplied by the allocated RBP Credit MW, \nwhere the zone/area committed RBP UCAP MW is allocated using the \nrelevant Load Serving Entity’s proportional share of the Daily Unforced \nCapacity Obligation for the zone/area as determined in accordance with \nRAA, Schedule 8.  For Load Serving Entities required to post RBP \nCollateral by this section 18.8(b)(i)(B)(2), the Office of the Interconnection \nmay evaluate whether such Load Serving Entity for unreasonable credit risk \nunder the Unreasonable Credit Risk provisions of Tariff, Attachment Q, \nSection II, and require additional RBP Collateral as appropriate. \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 committed RBP UCAP MW, as \ndetermined pursuant to Tariff, Attachment DD, section 18.3, then the \ntransferee LSE must fully satisfy all applicable credit and collateral \nrequirements required herein associated with such transferred committed \nRBP UCAP MW obligation and, as applicable, the credit requirements in \nTariff, Attachment Q.  Transferee shall independently post sufficient RBP \nCollateral directly with the Office of the Interconnection to satisfy the \nincremental committed RBP UCAP MW associated with the acquired load. \n \n(2) \nTransferor shall be released from its financial obligations for \namount of RBP Collateral associated with the committed RBP UCAP MW"},{"page":66,"startToken":24196,"endToken":24243,"text":"associated with the transferred load.  Any RBP Collateral posted by \ntransferor shall be returned once Transferee has posted the RBP Collateral \ndetermined in accordance with Tariff, Attachment DD, section 18.8(c) and \nany unpaid invoice amounts associated with such transfer have been paid \nby the transferor."}],"sections":[{"p":1,"at":0,"title":"Attachment B","method":"printed heading","endPage":2,"endAt":0,"startToken":0,"endToken":9},{"p":2,"at":0,"title":"Definitions – O – P - Q","method":"PDF bookmark","endPage":2,"endAt":638,"startToken":9,"endToken":105},{"p":2,"at":638,"title":"Offer Data:","method":"PDF bookmark","endPage":2,"endAt":1122,"startToken":105,"endToken":177},{"p":2,"at":1122,"title":"Office of the Interconnection:","method":"PDF bookmark","endPage":2,"endAt":1363,"startToken":177,"endToken":213},{"p":2,"at":1363,"title":"Office of the Interconnection Control Center:","method":"PDF bookmark","endPage":2,"endAt":1873,"startToken":213,"endToken":287},{"p":2,"at":1873,"title":"On-Site 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