{"document":{"slug":"filing-er26-3515-pjm-iras-attachment-2","title":"Attachment B- Clean Tariff 4930-8837-2935 v.2.pdf","issued":"2026-08-13","accession":"20260813-5118","docket":"ER26-3515-000","group":"PJM filings","filer":"PJM Interconnection, L.L.C.","kind":"attachment","file":"sources/originals/20260813-5118_03.pdf","url":"https://elibrary.ferc.gov/eLibrary/filelist?accession_Number=20260813-5118","parent":"filing-er26-3515-pjm-iras","sha256":"5f94d6023ed2841252d4c46afb266577e2173d72631b2b83f2af59c9845e948e","pages":145,"tokens":52007,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":16,"text":"Attachment B \nRevisions to the \nPJM Open Access Transmission Tariff \nand Resource Adequacy Agreement \n(Clean Format)"},{"page":2,"startToken":16,"endToken":374,"text":"Definitions – A - B \n \n30-minute Reserve:  \n \n“30-minute 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 30 minutes of a request from the Office of the Interconnection dispatcher, \nand is comprised of Synchronized Reserve, Non-Synchronized Reserve and Secondary Reserve.  \n \n30-minute Reserve Requirement:  \n \n“30-minute Reserve Requirement” shall mean the megawatts required to be maintained in a \nReserve Zone or Reserve Sub-zone, as Secondary Reserve, absent any increase to account for \nadditional reserves scheduled to address operational uncertainty.  The 30-minute Reserve \nRequirement is calculated in accordance with the PJM Manuals.  The requirement can be \nsatisfied by any combination of Synchronized Reserve, Non Synchronized Reserve or Secondary \nReserve resources.  \n \nAbnormal Condition: \n \n“Abnormal Condition” shall mean any condition on the Interconnection Facilities which, \ndetermined in accordance with Good Utility Practice, is: (i) outside normal operating parameters \nsuch that facilities are operating outside their normal ratings or that reasonable operating limits \nhave been exceeded; and (ii) could reasonably be expected to materially and adversely affect the \nsafe and reliable operation of the Interconnection Facilities; but which, in any case, could \nreasonably be expected to result in an Emergency Condition.  Any condition or situation that \nresults from lack of sufficient generating capacity to meet load requirements or that results solely \nfrom economic conditions shall not, standing alone, constitute an Abnormal Condition. \n \nAcceleration Request: \n \n“Acceleration Request” shall mean a request pursuant to Operating Agreement, Schedule 1, \nsection 1.9.4A, and the parallel provisions of Tariff, Attachment K-Appendix, section 1.9.4A, to \naccelerate or reschedule a transmission outage scheduled pursuant to Operating Agreement, \nSchedule 1, section 1.9.2 or Operating Agreement, Schedule 1, section 1.9.4, and the parallel \nprovisions of Tariff, Attachment K-Appendix, section 1.9.2 or Tariff, Attachment K-Appendix, \nsection 1.9.4. \n \nAffected System: \n \n“Affected System” shall mean an electric system other than the Transmission Provider’s \nTransmission System that may be affected by a proposed interconnection or on which a proposed \ninterconnection or addition of facilities or upgrades may require modifications or upgrades to the \nTransmission System. \n \nAffected System Operator:"},{"page":3,"startToken":374,"endToken":774,"text":"“Affected System Operator” shall mean an entity that operates an Affected System or, if the \nAffected System is under the operational control of an independent system operator or a regional \ntransmission organization, such independent entity. \n \nAffiliate: \n \n“Affiliate” shall mean any two or more entities, one of which Controls the other or that are under \ncommon Control.  “Control,” as that term is used in this definition, shall mean the possession, \ndirectly or indirectly, of the power to direct the management or policies of an entity.  Ownership \nof publicly-traded equity securities of another entity shall not result in Control or affiliation for \npurposes of the Tariff or Operating Agreement if the securities are held as an investment, the \nholder owns (in its name or via intermediaries) less than 10 percent (10%) of the outstanding \nsecurities of the entity, the holder does not have representation on the entity’s board of directors \n(or equivalent managing entity) or vice versa, and the holder does not in fact exercise influence \nover day-to-day management decisions.  Unless the contrary is demonstrated to the satisfaction \nof the Members Committee, Control shall be presumed to arise from the ownership of or the \npower to vote, directly or indirectly, ten percent or more of the voting securities of such entity. \n \nAgreements: \n \n“Agreements” shall mean the Amended and Restated Operating Agreement of PJM \nInterconnection, L.L.C., the PJM Open Access Transmission Tariff, the Reliability Assurance \nAgreement, and/or other agreements between PJM Interconnection, L.L.C. and its Members. \n \nAllocated RBP UCAP MW: \n \n“Allocated RBP UCAP MW” shall mean the RBP UCAP MW allocated to a New Large Load in \naccordance with Tariff, Attachment DD-4, section IX. \n \nAmbient-Adjusted Rating: \n \n“Ambient-Adjusted Rating” (AAR) shall mean a Transmission Facility Rating that:  \n \n(a) Applies to a time period of not greater than one hour. \n(b) Reflects an up-to-date forecast of ambient air temperature across the time period to \nwhich the rating applies. \n(c) Reflects the absence of solar heating during nighttime periods, where the local \nsunrise/sunset times used to determine daytime and nighttime periods are updated at \nleast monthly, if not more frequently. \n(d) Is evaluated at least each hour, if not more frequently.   \n \nAncillary Services: \n \n“Ancillary Services” shall mean those services that are necessary to support the transmission of \ncapacity and energy from resources to loads while maintaining reliable operation of the \nTransmission Provider’s Transmission System in accordance with Good Utility Practice."},{"page":4,"startToken":774,"endToken":1033,"text":"Annual Demand Resource: \n \n“Annual Demand Resource” shall have the meaning specified in the Reliability Assurance \nAgreement. \n \nAnnual Energy Efficiency Resource: \n \n“Annual Energy Efficiency Resource” shall have the meaning specified in the Reliability \nAssurance Agreement. \n \nAnnual Resource:  \n \n“Annual Resource” shall mean a Generation Capacity Resource, an Annual Energy Efficiency \nResource or an Annual Demand Resource.  \n \nAnnual Resource Price Adder:  \n \n“Annual Resource Price Adder” shall mean, for Delivery Years starting June 1, 2014 and ending \nMay 31, 2017,  an addition to the marginal value of Unforced Capacity and the Extended \nSummer Resource Price Adder as necessary to reflect the price of Annual Resources required to \nmeet the applicable Minimum Annual Resource Requirement. \n \nAnnual Revenue Rate: \n \n“Annual Revenue Rate” shall mean the rate employed to assess a compliance penalty charge on a \nCurtailment Service Provider under Tariff, Attachment DD, section 11. \n \nAnnual Transmission Costs: \n \n“Annual Transmission Costs” shall mean the total annual cost of the Transmission System for \npurposes of Network Integration Transmission Service shall be the amount specified in \nAttachment H for each Zone until amended by the applicable Transmission Owner or modified \nby the Commission. \n \nApplicable Laws and Regulations: \n \n“Applicable Laws and Regulations” shall mean all duly promulgated applicable federal, State \nand local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or \nadministrative orders, permits and other duly authorized actions of any Governmental Authority \nhaving jurisdiction over the relevant parties, their respective facilities, and/or the respective \nservices they provide. \n \nApplicable Regional Entity: \n \n“Applicable Regional Entity” shall mean the Regional Entity for the region in which a Network"},{"page":5,"startToken":1033,"endToken":1348,"text":"Customer, Transmission Customer, New Service Customer, or Transmission Owner operates. \n \nApplicable Standards: \n \n“Applicable Standards” shall mean the requirements and guidelines of NERC, the Applicable \nRegional Entity, and the Control Area in which the Customer Facility is electrically located; the \nPJM Manuals; and Applicable Technical Requirements and Standards. \n \nApplicable Technical Requirements and Standards: \n \n“Applicable Technical Requirements and Standards” shall mean those certain technical \nrequirements and standards applicable to interconnections of generation and/or transmission \nfacilities with the facilities of an Interconnected Transmission Owner or, as the case may be and \nto the extent applicable, of an Electric Distributor, as published by Transmission Provider in a \nPJM Manual provided, however, that, with respect to any generation facilities with maximum \ngenerating capacity of 2 MW or less (synchronous) or 5 MW or less (inverter-based) for which \nthe Interconnection Customer executes a Construction Service Agreement or Interconnection \nService Agreement on or after March 19, 2005, “Applicable Technical Requirements and \nStandards” shall refer to the “PJM Small Generator Interconnection Applicable Technical \nRequirements and Standards.”  All Applicable Technical Requirements and Standards shall be \npublicly available through postings on Transmission Provider’s internet website. \n \nApplicant: \n \n“Applicant” shall mean an entity desiring to become a PJM Member, become a Market \nParticipant, engage in market activities, or to take Transmission Service that has submitted the \nPJMSettlement credit application, PJMSettlement credit agreement and other required submittals \nas set forth in Tariff, Attachment Q. \n \nApplication: \n \n“Application” shall mean a request by an Eligible Customer for transmission service pursuant to \nthe provisions of the Tariff. \n \nAttachment Facilities: \n \n“Attachment Facilities” shall mean the facilities necessary to physically connect a Customer \nFacility to the Transmission System or interconnected distribution facilities. \n \nAttachment H: \n \n“Attachment H” shall refer collectively to the Attachments to the PJM Tariff with the prefix  \n“H” that set forth, among other things, the Annual Transmission Rates for Network Integration \nTransmission Service in the PJM Zones. \n \nAuction Revenue Rights:"},{"page":6,"startToken":1348,"endToken":1700,"text":"“Auction Revenue Rights” or “ARRs” shall mean the right to receive the revenue from the \nFinancial Transmission Right auction, as further described in Operating Agreement, Schedule 1, \nsection 7.4, and the parallel provisions of Tariff, Attachment K-Appendix, section 7.4. \n \nAuction Revenue Rights Credits: \n \n“Auction Revenue Rights Credits” shall mean the allocated share of total FTR auction revenues \nor costs credited to each holder of Auction Revenue Rights, calculated and allocated as specified \nin Operating Agreement, Schedule 1, section 7.4.3, and the parallel provisions of Tariff, \nAttachment K-Appendix, section 7.4.3. \n \nAuthorized Government Agency: \n \n“Authorized Government Agency” means a regulatory body or government agency, with \njurisdiction over PJM, the PJM Market, or any entity doing business in the PJM Market, including, \nbut not limited to, the Commission, State Commissions, and state and federal attorneys general. \n \nAvoidable Cost Rate: \n \n“Avoidable Cost Rate” shall mean a component of the Market Seller Offer Cap calculated in \naccordance with Tariff, Attachment DD, section 6. \n \nBalancing Congestion Charges: \n \n“Balancing Congestion Charges” shall be equal to the sum of congestion charges collected from \nMarket Participants that are purchasing energy in the Real-time Energy Market minus [the sum \nof congestion charges paid to Market Participants that are selling energy in the Real-time Energy \nMarket plus any congestion charges calculated pursuant to the Joint Operating Agreement \nbetween the Midcontinent Independent Transmission System Operator, Inc. and PJM \nInterconnection, L.L.C. (PJM Rate Schedule FERC No. 38), plus any congestion charges \ncalculated pursuant to the Joint Operating Agreement Among and Between New York \nIndependent System Operator Inc. and PJM Interconnection, L.L.C. (PJM Rate Schedule FERC \nNo. 45), plus any congestion charges calculated pursuant to agreements between the Office of \nthe Interconnection and other entities, plus any charges or credits calculated pursuant to \nOperating Agreement, Schedule 1, section 3.8, and the parallel provisions of Tariff, Attachment \nK-Appendix, section 3.8, as applicable)]. \n \nBalancing Ratio: \n \n“Balancing Ratio” shall have the meaning provided in Tariff, Attachment DD, section 10A. \n \nBase Capacity Demand Resource:  \n \n“Base Capacity Demand Resource” shall have the meaning specified in the Reliability Assurance \nAgreement."},{"page":7,"startToken":1700,"endToken":2211,"text":"Base Capacity Demand Resource Constraint: \n \n“Base Capacity Demand Resource Constraint” for the PJM Region or an LDA, shall mean, for \nthe 2018/2019 and 2019/2020 Delivery Years, the maximum Unforced Capacity amount, \ndetermined by PJM, of Base Capacity Demand Resources and Base Capacity Energy Efficiency \nResources that is consistent with the maintenance of reliability.  As more fully set forth in the \nPJM Manuals, PJM calculates the Base Capacity Demand Resource Constraint for the PJM \nRegion or an LDA, by first determining a reference annual loss of load expectation (“LOLE”) \nassuming no Base Capacity Resources, including no Base Capacity Demand Resources or Base \nCapacity Energy Efficiency Resources.  The calculation for the PJM Region uses a daily \ndistribution of loads under a range of weather scenarios (based on the most recent load forecast \nand iteratively shifting the load distributions to result in the Installed Reserve Margin established \nfor the Delivery Year in question) and a weekly capacity distribution (based on the cumulative \ncapacity availability distributions developed for the Installed Reserve Margin study for the \nDelivery Year in question).  The calculation for each relevant LDA uses a daily distribution of \nloads under a range of weather scenarios (based on the most recent load forecast for the Delivery \nYear in question) and a weekly capacity distribution (based on the cumulative capacity \navailability distributions developed for the Installed Reserve Margin study for the Delivery Year \nin question).  For the relevant LDA calculation, the weekly capacity distributions are adjusted to \nreflect the Capacity Emergency Transfer Limit for the Delivery Year in question. \n \nFor both the PJM Region and LDA analyses, PJM then models the commitment of varying \namounts of Base Capacity Demand Resources and Base Capacity Energy Efficiency Resources \n(displacing otherwise committed generation) as interruptible from June 1 through September 30 \nand unavailable the rest of the Delivery Year in question and calculates the LOLE at each DR \nand EE level.  The Base Capacity Demand Resource Constraint is the combined amount of Base \nCapacity Demand Resources and Base Capacity Energy Efficiency Resources, stated as a \npercentage of the unrestricted annual peak load, that produces no more than a five percent \nincrease in the LOLE, compared to the reference value.  The Base Capacity Demand Resource \nConstraint shall be expressed as a percentage of the forecasted peak load of the PJM Region or \nsuch LDA and is converted to Unforced Capacity by multiplying [the reliability target \npercentage] times [the Forecast Pool Requirement] times [the forecasted peak load of the PJM \nRegion or such LDA, reduced by the amount of load served under the FRR Alternative]. \n \nBase Capacity Demand Resource Price Decrement: \n \n“Base Capacity Demand Resource Price Decrement” shall mean, for the 2018/2019 and \n2019/2020 Delivery Years, a difference between the clearing price for Base Capacity Demand \nResources and Base Capacity Energy Efficiency Resources and the clearing price for Base \nCapacity Resources and Capacity Performance Resources, representing the cost to procure \nadditional Base Capacity Resources or Capacity Performance Resources out of merit order when \nthe Base Capacity Demand Resource Constraint is binding. \n \nBase Capacity Energy Efficiency Resource:"},{"page":8,"startToken":2211,"endToken":2726,"text":"“Base Capacity Energy Efficiency Resource” shall have the meaning specified in the Reliability \nAssurance Agreement. \n \nBase Capacity Resource:  \n \n“Base Capacity Resource” shall mean a Capacity Resource as described in Tariff, Attachment \nDD, section 5.5A(b). \n \nBase Capacity Resource Constraint: \n \n“Base Capacity Resource Constraint” for the PJM Region or an LDA, shall mean, for the \n2018/2019 and 2019/2020 Delivery Years, the maximum Unforced Capacity amount, determined \nby PJM, of Base Capacity Resources, including Base Capacity Demand Resources and Base \nCapacity Energy Efficiency Resources, that is consistent with the maintenance of reliability.  As \nmore fully set forth in the PJM Manuals, PJM calculates the above Base Capacity Resource \nConstraint for the PJM Region or an LDA, by first determining a reference annual loss of load \nexpectation (“LOLE”) assuming no Base Capacity Resources, including no Base Capacity \nDemand Resources or Base Capacity Energy Efficiency Resources.  The calculation for the PJM \nRegion uses the weekly load distribution from the Installed Reserve Margin study for the \nDelivery Year in question (based on the most recent load forecast and iteratively shifting the load \ndistributions to result in the Installed Reserve Margin established for the Delivery Year in \nquestion) and a weekly capacity distribution (based on the cumulative capacity availability \ndistributions developed for the Installed Reserve Margin study for the Delivery Year in \nquestion).  The calculation for each relevant LDA uses a weekly load distribution (based on the \nInstalled Reserve Margin study and the most recent load forecast for the Delivery Year in \nquestion) and a weekly capacity distribution (based on the cumulative capacity availability \ndistributions developed for the Installed Reserve Margin study for the Delivery Year in \nquestion).  For the relevant LDA calculation, the weekly capacity distributions are adjusted to \nreflect the Capacity Emergency Transfer Limit for the Delivery Year in question.  Additionally, \nfor the PJM Region and relevant LDA calculation, the weekly capacity distributions are adjusted \nto reflect winter ratings. \n \nFor both the PJM Region and LDA analyses, PJM models the commitment of an amount of Base \nCapacity Demand Resources and Base Capacity Energy Efficiency Resources equal to the Base \nCapacity Demand Resource Constraint (displacing otherwise committed generation).  PJM then \nmodels the commitment of varying amounts of Base Capacity Resources (displacing otherwise \ncommitted generation) as unavailable during the peak week of winter and available the rest of \nthe Delivery Year in question and calculates the LOLE at each Base Capacity Resource level.  \nThe Base Capacity Resource Constraint is the combined amount of Base Capacity Demand \nResources, Base Capacity Energy Efficiency Resources and Base Capacity Resources, stated as a \npercentage of the unrestricted annual peak load, that produces no more than a ten percent \nincrease in the LOLE, compared to the reference value.  The Base Capacity Resource Constraint \nshall be expressed as a percentage of the forecasted peak load of the PJM Region or such LDA \nand is converted to Unforced Capacity by multiplying [the reliability target percentage] times \n[one minus the pool-wide average EFORd] times [the forecasted peak load of the PJM Region or \nsuch LDA, reduced by the amount of load served under the FRR Alternative]."},{"page":9,"startToken":2726,"endToken":3101,"text":"Base Capacity Resource Price Decrement: \n \n“Base Capacity Resource Price Decrement” shall mean, for the 2018/2019 and 2019/2020 \nDelivery Years, a difference between the clearing price for Base Capacity Resources and the \nclearing price for Capacity Performance Resources, representing the cost to procure additional \nCapacity Performance Resources out of merit order when the Base Capacity Resource Constraint \nis binding. \n \nBase Load Generation Resource \n \n“Base Load Generation Resource” shall mean a Generation Capacity Resource that operates at \nleast 90 percent of the hours that it is available to operate, as determined by the Office of the \nInterconnection in accordance with the PJM Manuals. \n \nBase Offer Segment: \n \n“Base Offer Segment” shall mean a component of a Sell Offer based on an existing Generation \nCapacity Resource, equal to the Unforced Capacity of such resource, as determined in \naccordance with the PJM Manuals.  If the Sell Offers of multiple Market Sellers are based on a \nsingle Existing Generation Capacity Resource, the Base Offer Segments of such Market Sellers \nshall be determined pro rata based on their entitlements to Unforced Capacity from such \nresource. \n \nBase Residual Auction:  \n \n“Base Residual Auction” shall mean the auction conducted three years prior to the start of the \nDelivery Year to secure commitments from Capacity Resources as necessary to satisfy any \nportion of the Unforced Capacity Obligation of the PJM Region not satisfied through Self-\nSupply. \n \nBatch Load Economic Load Response Participant Resource: \n \n“Batch Load Economic Load Response Participant Resource” shall mean an Economic Load \nResponse Participant Resource that has a cyclical production process such that at most times \nduring the process it is consuming energy, but at consistent regular intervals, ordinarily for \nperiods of less than ten minutes, it reduces its consumption of energy for its production processes \nto minimal or zero megawatts. \n \nBehind The Meter Generation: \n \n“Behind The Meter Generation” shall refer to a generation unit that delivers energy to load \nwithout using the Transmission System or any distribution facilities (unless the entity that owns \nor leases the distribution facilities has consented to such use of the distribution facilities and such \nconsent has been demonstrated to the satisfaction of the Office of the Interconnection); provided, \nhowever, that Behind The Meter Generation does not include (i) at any time, any portion of such"},{"page":10,"startToken":3101,"endToken":3436,"text":"generating unit’s capacity that is designated as a Generation Capacity Resource; or (ii) in an \nhour, any portion of the output of such generating unit that is sold to another entity for \nconsumption at another electrical location or into the PJM Interchange Energy Market. \n \nBlack Start Service: \n \n“Black Start Service” shall mean the capability of generating units to start without an outside \nelectrical supply or the demonstrated ability of a generating unit with a high operating factor \n(subject to Transmission Provider concurrence) to automatically remain operating at reduced \nlevels when disconnected from the grid. \n \nBorder Yearly Charge: \n \n“Border Yearly Charge” shall mean the yearly charge determined in accordance with Tariff, \nSchedule 7. \n \nBreach: \n \n“Breach” shall mean the failure of a party to perform or observe any material term or condition \nof Tariff, Part IV or Tariff, Part VI, or any agreement entered into thereunder as described in the \nrelevant provisions of such agreement. \n \nBreaching Party: \n \n“Breaching Party” shall mean a party that is in Breach of Tariff, Part IV or Tariff, Part VI and/or \nan agreement entered into thereunder. \n \nBring Your Own New Capacity: \n \n“Bring Your Own New Capacity” or “BYONC” shall mean megawatts of Unforced Capacity \nthat meet the eligibility criteria set forth in Tariff, Attachment DD-4, section VI.  Megawatts of \nUnforced Capacity that have been previously included in an FRR Capacity Plan prior to the \n2027/2028 Delivery Year do not qualify as BYONC. However, to the extent three consecutive \nDelivery Years meet the requirements of Tariff, Attachment DD-4, section IV(b)(iii), then \nBYONC that has been included previously in an FRR Capacity Plan prior to the first Delivery \nYear for which the requirements of Tariff, Attachment DD-4, section IV(b)(iii) are not met and \n(2) meet the eligibility criteria set forth in Tariff, Attachment DD-4, section VI do not qualify as \nBYONC. \n \nBusiness Day: \n \n“Business Day” shall mean a day in which the Federal Reserve System is open for business and \nis not a scheduled PJM holiday. \n \nBuy Bid:"},{"page":11,"startToken":3436,"endToken":3488,"text":"“Buy Bid” shall mean a bid to buy Capacity Resources in any Incremental Auction. \n \nBuyer-Side Market Power: \n \n“Buyer-Side Market Power” shall mean the ability of Capacity Market Sellers with a Load \nInterest to suppress RPM Auction clearing prices for the overall benefit of their (and/or affiliates) \nportfolio of generation and load."},{"page":12,"startToken":3488,"endToken":3797,"text":"Definitions – E - F \n \nEconomic-based Enhancement or Expansion: \n \n“Economic-based Enhancement or Expansion” shall have the same meaning provided in the \nOperating Agreement. \n \nEconomic Load Response Participant: \n \n“Economic Load Response Participant” shall mean a Member or Special Member that qualifies \nunder Operating Agreement, Schedule 1, section 1.5A, and the parallel provisions of Tariff, \nAttachment K-Appendix, section 1.5A, to participate in the PJM Interchange Energy Market \nand/or Ancillary Services markets through reductions in demand. \n \nEconomic Load Response Regulation Only Participant:  \n \n“Economic Load Response Regulation Only Participant” shall mean a Member or Special \nMember that qualifies under Operating Agreement, Schedule 1, section 1.5A, and the parallel \nprovisions of Tariff, Attachment K-Appendix, section 1.5A, and is only eligible to participate in \nthe PJM Regulation market. \n \nEconomic Maximum: \n \n“Economic Maximum” shall mean the highest incremental MW output level, submitted to PJM \nmarket systems by a Market Participant, that a unit can achieve while following economic \ndispatch.   \n \nEconomic Minimum: \n \n“Economic Minimum” shall mean the lowest incremental MW output level, submitted to PJM \nmarket systems by a Market Participant, that a unit can achieve while following economic \ndispatch. \n \nEffective FTR Holder: \n \n“Effective FTR Holder” shall mean: \n \n(i) For an FTR Holder that is either a (a) privately held company, or (b) a municipality or \nelectric cooperative, as defined in the Federal Power Act, such FTR Holder, together with \nany Affiliate, subsidiary or parent of the FTR Holder, any other entity that is under common \nownership, wholly or partly, directly or indirectly, or has the ability to influence, directly or \nindirectly, the management or policies of the FTR Holder; or  \n \n(ii) For an FTR Holder that is a publicly traded company including a wholly owned \nsubsidiary of a publicly traded company, such FTR Holder, together with any Affiliate, \nsubsidiary or parent of the FTR Holder, any other PJM Member has over 10% common"},{"page":13,"startToken":3797,"endToken":4154,"text":"ownership with the FTR Holder, wholly or partly, directly or indirectly, or has the ability to \ninfluence, directly or indirectly, the management or policies of the FTR Holder; or  \n \n(iii)  an FTR Holder together with any other PJM Member, including also any Affiliate, \nsubsidiary or parent of such other PJM Member, with which it shares common ownership, \nwholly or partly, directly or indirectly, in any third entity which is a PJM Member (e.g., a \njoint venture). \n \n \nEFORd: \n \n“EFORd” shall have the meaning specified in the PJM Reliability Assurance Agreement. \n \nElectrical Distance: \n \n“Electrical Distance” shall mean, for a Generation Capacity Resource geographically located \noutside the metered boundaries of the PJM Region, the measure of distance, based on impedance \nand in accordance with the PJM Manuals, from the Generation Capacity Resource to the PJM \nRegion. \n \nEligible Customer: \n \n“Eligible Customer” shall mean: \n \n(i) Any electric utility (including any Transmission Owner and any power marketer), Federal \npower marketing agency, or any person generating electric energy for sale for resale is an \nEligible Customer under the Tariff.  Electric energy sold or produced by such entity may be \nelectric energy produced in the United States, Canada or Mexico.  However, with respect to \ntransmission service that the Commission is prohibited from ordering by Section 212(h) of the \nFederal Power Act, such entity is eligible only if the service is provided pursuant to a state \nrequirement that the Transmission Provider or Transmission Owner offer the unbundled \ntransmission service, or pursuant to a voluntary offer of such service by a Transmission Owner. \n \n(ii) Any retail customer taking unbundled transmission service pursuant to a state requirement \nthat the Transmission Provider or a Transmission Owner offer the transmission service, or \npursuant to a voluntary offer of such service by a Transmission Owner, is an Eligible Customer \nunder the Tariff.  As used in Tariff, Part VI, Eligible Customer shall mean only those Eligible \nCustomers that have submitted a Completed Application. \n \nEligible Fast-Start Resource: \n \n“Eligible Fast-Start Resource” shall mean a Fast-Start Resource that is eligible for the \napplication of Integer Relaxation during the calculation of Locational Marginal Prices as set \nforth in Tariff, Attachment K-Appendix, section 2.2."},{"page":14,"startToken":4154,"endToken":4580,"text":"Eligible New Large Loads: \n \n“Eligible New Large Loads” shall mean a New Large Load eligible to provide Interim Resource \nAdequacy Service in accordance with Tariff, Attachment DD-4, section V. \n \nEligible New Large Load Amount: \n \n“Eligible New Large Load Amount” shall mean the total megawatt value of load an Eligible \nNew Large Load may be required to make available for Interim Resource Adequacy Service in \nan Electric Distributor zone/area. \n \nEmergency Action: \n \n“Emergency Action” shall mean (1) any megawatt shortage of the Primary Reserve Requirement \n(as specified in the PJM Manuals) in a Reserve Zone or Reserve Sub-zone, inclusive of any \nadjustments to such requirement to account for system conditions, as determined by the dispatch \nrun from the security constrained economic dispatch and where, as specified in the PJM \nManuals, there is also a Voltage Reduction Warning and reduction of non-critical plant load, \nManual Load Dump Warning, Maximum Generation Emergency Action, or the curtailment of \nnon-essential building loads and Voltage Reduction Warning that encompasses such Reserve \nZone or Reserve Sub-zone or (2) anytime the Office of Interconnection identifies an emergency \nand issues a load shed directive, Manual Load Dump Action, Voltage Reduction Action, or \ndeploy all resources action for an entire Reserve Zone or Reserve Sub-zone. \n \nEmergency Condition: \n \n“Emergency Condition” shall mean a condition or situation (i) that in the judgment of any \nInterconnection Party is imminently likely to endanger life or property; or (ii) that in the \njudgment of the Interconnected Transmission Owner or Transmission Provider is imminently \nlikely (as determined in a non-discriminatory manner) to cause a material adverse effect on the \nsecurity of, or damage to, the Transmission System, the Interconnection Facilities, or the \ntransmission systems or distribution systems to which the Transmission System is directly or \nindirectly connected; or (iii) that in the judgment of Interconnection Customer is imminently \nlikely (as determined in a non-discriminatory manner) to cause damage to the Customer Facility \nor to the Customer Interconnection Facilities.  System restoration and black start shall be \nconsidered Emergency Conditions, provided that a Generation Interconnection Customer is not \nobligated by an Interconnection Service Agreement to possess black start capability.  Any \ncondition or situation that results from lack of sufficient generating capacity to meet load \nrequirements or that results solely from economic conditions shall not constitute an Emergency \nCondition, unless one or more of the enumerated conditions or situations identified in this \ndefinition also exists. \n \nEmergency Load Response Program: \n“Emergency Load Response Program” shall mean the program by which Curtailment Service \nProviders may be compensated by PJM for Demand Resources that will reduce load when"},{"page":15,"startToken":4580,"endToken":4888,"text":"dispatched by PJM during emergency conditions, and is described in Operating Agreement, \nSchedule 1, section 8  and the parallel provisions of Tariff, Attachment K-Appendix, section 8.  \n \nEnergy Efficiency Resource: \n \n“Energy Efficiency Resource” shall have the meaning specified in the PJM Reliability Assurance \nAgreement. \n \nEnergy Market Opportunity Cost: \n \n“Energy Market Opportunity Cost” shall mean the difference between (a) the forecasted cost to \noperate a specific generating unit when the unit only has an operational limitation due to \nlimitations imposed on the unit by Applicable Laws and Regulations, and (b) the forecasted \nfuture Locational Marginal Price at which the generating unit could run while not violating such \nlimitations.  Energy Market Opportunity Cost therefore is the value associated with a specific \ngenerating unit’s lost opportunity to produce energy during a higher valued period of time \noccurring within the same compliance period, which compliance period is determined by the \napplicable regulatory authority and is reflected in the rules set forth in PJM Manual 15.  Energy \nMarket Opportunity Costs shall be limited to those resources which are specifically delineated in \nOperating Agreement, Schedule 2. \n \nEnergy Resource: \n \n“Energy Resource” shall mean a Generating Facility that is not a Capacity Resource. \n \nEnergy Settlement Area: \n \n“Energy Settlement Area” shall mean the bus or distribution of busses that represents the \nphysical location of Network Load and by which the obligations of the Network Customer to \nPJM are settled. \n \nEnergy Storage Resource: \n \n“Energy Storage Resource” shall mean a resource capable of receiving electric energy from the \ngrid and storing it for later injection to the grid that participates in the PJM Energy, Capacity \nand/or Ancillary Services markets as a Market Participant.  Open-Loop Hybrid Resources are not \nEnergy Storage Resources. \n \nEnergy Storage Resource Model Participant:  \n \n“Energy Storage Resource Model Participant” shall mean an Energy Storage Resource utilizing \nthe Energy Storage Resource Participation Model.   \n \nEnergy Storage Resource Participation Model:"},{"page":16,"startToken":4888,"endToken":5227,"text":"“Energy Storage Resource Participation Model” shall mean the participation model accepted by \nthe Commission in Docket No. ER19-469-000. \n \nEnergy Transmission Injection Rights: \n \n“Energy Transmission Injection Rights” shall mean the rights to schedule energy deliveries at a \nspecified point on the Transmission System. Energy Transmission Injection Rights may be \nawarded only to a Merchant D.C. Transmission Facility that connects the Transmission System \nto another control area. Deliveries scheduled using Energy Transmission Injection Rights have \nrights similar to those under Non-Firm Point-to-Point Transmission Service. \n \nEntity Providing Supply Services to Default Retail Service Provider: \n \n“Entity Providing Supply Services to Default Retail Service Provider” shall mean any entity, \nincluding but not limited to a load aggregator or power marketer, providing supply services to an \nelectric distribution company when that electric distribution company is serving as the default \nretail service provider, and that enters into a contract or similar obligation with such electric \ndistribution company to serve retail customers who have not selected a competitive retail service \nprovider.  \n \nEnvironmental Laws: \n \n“Environmental Laws” shall mean applicable Laws or Regulations relating to pollution or \nprotection of the environment, natural resources or human health and safety. \n \nEnvironmentally-Limited Resource: \n \n“Environmentally-Limited Resource” shall mean a resource which has a limit on its run hours \nimposed by a federal, state, or other governmental agency that will significantly limit its \navailability, on either a temporary or long-term basis. This includes a resource that is limited by a \ngovernmental authority to operating only during declared PJM capacity emergencies. \n \nEquivalent Load: \n \n“Equivalent Load” shall mean the sum of a Market Participant’s net system requirements to \nserve its customer load in the PJM Region, if any, plus its net bilateral transactions. \n \nEvent of Default: \n \n“Event of Default,” as that term is used in Tariff, Attachment Q, shall mean a Financial Default, \nCredit Breach, or Credit Support Default.   \n \nExcluded LDA New Large Load Amounts: \n \n“Excluded LDA New Large Load Amounts” shall mean, converted in UCAP terms by estimating \nthe impact on required imports to a Locational Deliverability Area and exclusive of any load in"},{"page":17,"startToken":5227,"endToken":5671,"text":"an FRR Service Area, [the sum of all New Large Loads in the relevant Locational Deliverability \nArea that were included in the load forecast for the relevant Delivery Year] minus [New Large \nLoads in the relevant Locational Deliverability Area that were included in the load forecast used \nfor the 2028/2029 Delivery Year] minus [the total MW quantity of New Large Load that is added \non or after the 2029/2030 Delivery Year and is (i) in an arrangement with BYONC in the \nLocational Deliverability Area or (ii) assigned Allocated RBP UCAP MW in Locational \nDeliverability Area]. \n \nExcluded RTO New Large Load Amounts \n \n“Excluded RTO New Large Load Amounts” shall mean, converted in UCAP terms by using the \nForecast Pool Requirement and exclusive of any load in an FRR Service Area, [the sum of all \nNew Large Loads across the PJM Region in the load forecast for the relevant Delivery Year] \nminus [New Large Loads across the PJM Region that were included in the load forecast used for \nthe 2028/2029 Delivery Year] minus [the total MW quantity of New Large Load that is added on \nor after the 2029/2030 Delivery Year and is (i) in an arrangement with BYONC in the RTO or \n(ii) assigned Allocated RBP UCAP MW in the RTO]. \n \nExercise of Buyer-Side Market Power: \n \n“Exercise of Buyer-Side Market Power” shall mean anti-competitive behavior of a Capacity \nMarket Seller with a Load Interest, or directed by an entity with a Load Interest, to \nuneconomically lower RPM Auction Sell Offer(s) in order to suppress RPM Auction clearing \nprices for the overall benefit of the Capacity Market Seller’s (and/or affiliates of Capacity \nMarket Seller) portfolio of generation and load or that of the directing entity with a Load Interest \nas determined pursuant to Tariff, Attachment DD, section 5.14(h-2)(2)(B). A bilateral contract \nbetween the Capacity Market Seller and an entity with a Load Interest with the express purpose \nof lowering capacity market clearing prices shall be evidence of the Exercise of Buyer-Side \nMarket Power. \n \nExisting Generation Capacity Resource: \n \n“Existing Generation Capacity Resource” shall have the meaning specified in the Reliability \nAssurance Agreement. \n \nExport Credit Exposure: \n  \n“Export Credit Exposure” is determined for each Market Participant for a given Operating Day, \nand shall mean the sum of credit exposures for the Market Participant’s Export Transactions for \nthat Operating Day and for the preceding Operating Day. \n \nExport Nodal Reference Price: \n \n“Export Nodal Reference Price” at each location is the 97th percentile, shall be, the real-time \nhourly integrated price experienced over the corresponding two-month period in the preceding \ncalendar year, calculated separately for peak and off-peak time periods.  The two-month time"},{"page":18,"startToken":5671,"endToken":6048,"text":"periods used in this calculation shall be January and February, March and April, May and June, \nJuly and August, September and October, and November and December.  \n \nExport Transaction: \n  \n“Export Transaction” shall be a transaction by a Market Participant that results in the transfer of \nenergy from within the PJM Control Area to outside the PJM Control Area.  Coordinated \nExternal Transactions that result in the transfer of energy from the PJM Control Area to an \nadjacent Control Area are one form of Export Transaction.   \n \nExport Transaction Price Factor: \n \n“Export Transaction Price Factor” for a prospective time interval shall be the greater of (i) PJM’s \nforecast price for the time interval, if available, or (ii) the Export Nodal Reference Price, but \nshall not exceed the Export Transaction’s dispatch ceiling price cap, if any, for that time interval.  \nThe Export Transaction Price Factor for a past time interval shall be calculated in the same \nmanner as for a prospective time interval, except that the Export Transaction Price Factor may \nuse a tentative or final settlement price, as available. If an Export Nodal Reference Price is not \navailable for a particular time interval, PJM may use an Export Transaction Price Factor for that \ntime interval based on an appropriate alternate reference price. \n \nExport Transaction Screening: \n \n“Export Transaction Screening” shall be the process PJM uses to review the Export Credit \nExposure of Export Transactions against the Credit Available for Export Transactions, and deny \nor curtail all or a portion of an Export Transaction, if the credit required for such transactions is \ngreater than the credit available for the transactions.   \n \nExport Transactions Net Activity: \n \n“Export Transactions Net Activity” shall mean the aggregate net total, resulting from Export \nTransactions, of (i) Spot Market Energy charges, (ii) Transmission Congestion Charges, and (iii) \nTransmission Loss Charges, calculated as set forth in Operating Agreement, Schedule 1 and the \nparallel provisions of Tariff, Attachment K-Appendix.  Export Transactions Net Activity may be \npositive or negative. \n \nExtended Primary Reserve Requirement: \n \n“Extended Primary Reserve Requirement” shall equal the Primary Reserve Requirement in a \nReserve Zone or Reserve Sub-zone, plus 190 MW, plus any additional reserves scheduled under \nemergency conditions necessary to address operational uncertainty.  The Extended Primary \nReserve Requirement is calculated in accordance with the PJM Manuals.  \n \nExtended Synchronized Reserve Requirement:"},{"page":19,"startToken":6048,"endToken":6395,"text":"“Extended Synchronized Reserve Requirement” shall equal the Synchronized Reserve \nRequirement in a Reserve Zone or Reserve Sub-zone, plus 190 MW, plus any additional reserves \nscheduled under emergency conditions necessary to address operational uncertainty. The \nExtended Synchronized Reserve Requirement is calculated in accordance with the PJM Manuals. \n \nExtended 30-minute Reserve Requirement: \n \n“Extended 30-minute Reserve Requirement” shall equal the 30-minute Reserve Requirement in a \nReserve Zone or Reserve Sub-zone, plus 190 MW, plus any additional reserves scheduled under \nemergency conditions necessary to address operational uncertainty.  The Extended 30-minute \nReserve Requirement is calculated in accordance with the PJM Manuals. \n \nExternal Market Buyer: \n \n“External Market Buyer” shall mean a Market Buyer making purchases of energy from the PJM \nInterchange Energy Market for consumption by end-users outside the PJM Region, or for load in \nthe PJM Region that is not served by Network Transmission Service. \n \nExternal Resource: \n \n“External Resource” shall mean a generation resource located outside the metered boundaries of \nthe PJM Region. \n \nFacilities Study: \n \n“Facilities Study” shall be an engineering study conducted by the Transmission Provider (in \ncoordination with the affected Transmission Owner(s)) to: (1) determine the required \nmodifications to the Transmission Provider’s Transmission System necessary to implement the \nconclusions of the System Impact Study; and (2) complete any additional studies or analyses \ndocumented in the System Impact Study or required by PJM Manuals, and determine the \nrequired modifications to the Transmission Provider’s Transmission System based on the \nconclusions of such additional studies.  The Facilities Study shall include the cost and scheduled \ncompletion date for such modifications, that will be required to provide the requested \ntransmission service or to accommodate a New Service Request.  As used in the Interconnection \nService Agreement or Construction Service Agreement, Facilities Study shall mean that certain \nFacilities Study conducted by Transmission Provider (or at its direction) to determine the design \nand specification of the Customer Funded Upgrades necessary to accommodate the New Service \nCustomer’s New Service Request in accordance with Tariff, Part VI, section 207.  \n \nFast-Start Resource:  \n \n“Fast-Start Resource” shall have the meaning set forth in Tariff, Attachment K-Appendix, \nsection 2.2A \n \nFederal Power Act:"},{"page":20,"startToken":6395,"endToken":6780,"text":"“Federal Power Act” shall mean the Federal Power Act, as amended, 16 U.S.C. §§ 791a, et seq. \n \nFERC or Commission: \n \n“FERC” or “Commission” shall mean the Federal Energy Regulatory Commission or any \nsuccessor federal agency, commission or department exercising jurisdiction over the Tariff, \nOperating Agreement and Reliability Assurance Agreement. \n \nFERC Market Rules: \n \n “FERC Market Rules” mean the market behavior rules and the prohibition against electric \nenergy market manipulation codified by the Commission in its Rules and Regulations at 18 CFR \n§§ 1c.2 and 35.37, respectively; the Commission-approved PJM Market Rules and any related \nproscriptions or any successor rules that the Commission from time to time may issue, approve \nor otherwise establish.  \n \nFinal Offer: \n \n“Final Offer” shall mean the offer on which a resource was dispatched by the Office of the \nInterconnection for a particular clock hour for the Operating Day. \n \nFinal RTO Unforced Capacity Obligation: \n \n“Final RTO Unforced Capacity Obligation” shall mean the capacity obligation for the PJM \nRegion, determined in accordance with RAA, Schedule 8. \n \nFinancial Close: \n \n“Financial Close” shall mean the Capacity Market Seller has demonstrated that the Capacity \nMarket Seller or its agent has completed the act of executing the material contracts and/or other \ndocuments necessary to (1) authorize construction of the project and (2) establish the necessary \nfunding for the project under the control of an independent third-party entity.  A sworn, notarized \ncertification of an independent engineer certifying to such facts, and that the engineer has \npersonal knowledge of, or has engaged in a diligent inquiry to determine, such facts, shall be \nsufficient to make such demonstration.  For resources that do not have external financing, \nFinancial Close shall mean the project has full funding available, and that the project has been \nduly authorized to proceed with full construction of the material portions of the project by the \nappropriate governing body of the company funding such project.  A sworn, notarized \ncertification by an officer of such company certifying to such facts, and that the officer has \npersonal knowledge of, or has engaged in a diligent inquiry to determine, such facts, shall be \nsufficient to make such demonstration. \n \nFinancial Default: \n \n“Financial Default” shall mean (a) the failure of a Member or Transmission Customer to make \nany payment for obligations under the Agreements when due, including but not limited to an"},{"page":21,"startToken":6780,"endToken":7154,"text":"invoice payment that has not been cured or remedied after notice has been given and any cure \nperiod has elapsed, (b) a bankruptcy proceeding filed by a Member, Transmission Customer or \nits Guarantor, or filed against a Member, Transmission Customer or its Guarantor and to which \nthe Member, Transmission Customer or Guarantor, as applicable, acquiesces or that is not \ndismissed within 60 days, (c) a Member, Transmission Customer or its Guarantor, if any, is \nunable to meet its financial obligations as they become due, or (d) a Merger Without Assumption \noccurs in respect of the Member, Transmission Customer or any Guarantor of such Member or \nTransmission Customer. \n \nFinancial Transmission Right: \n \n“Financial Transmission Right” or “FTR” shall mean a right to receive Transmission Congestion \nCredits as specified in Operating Agreement, Schedule 1, section 5.2.2 and the parallel \nprovisions of Tariff, Attachment K-Appendix, section 5.2.2. \n \nFinancial Transmission Right Obligation: \n \n“Financial Transmission Right Obligation” shall mean a right to receive Transmission \nCongestion Credits as specified in Operating Agreement, Schedule 1, section 5.2.2(b), and the \nparallel provisions of Tariff, Attachment K-Appendix, section 5.2.2(b). \n \nFinancial Transmission Right Option: \n \n“Financial Transmission Right Option” shall mean a right to receive Transmission Congestion \nCredits as specified in Operating Agreement, Schedule 1, section 5.2.2(c), and the parallel \nprovisions of Tariff, Attachment K-Appendix, section 5.2.2(c). \n \nFirm Point-To-Point Transmission Service: \n \n“Firm Point-To-Point Transmission Service” shall mean Transmission Service under the Tariff, \nPart II, section 13 that is reserved and/or scheduled between specified Points of Receipt and \nDelivery pursuant to Tariff, Part II. \n \nFirm Transmission Feasibility Study: \n \n“Firm Transmission Feasibility Study” shall mean a study conducted by the Transmission \nProvider in accordance with Tariff, Part II, section 19.3 and Tariff, Part III, section 32.3. \n \nFirm Transmission Withdrawal Rights: \n \n“Firm Transmission Withdrawal Rights” shall mean the rights to schedule energy and capacity \nwithdrawals from a Point of Interconnection of a Merchant Transmission Facility with the \nTransmission System. Firm Transmission Withdrawal Rights may be awarded only to a \nMerchant D.C. Transmission Facility that connects the Transmission System with another \ncontrol area. Withdrawals scheduled using Firm Transmission Withdrawal Rights have rights \nsimilar to those under Firm Point-to-Point Transmission Service."},{"page":22,"startToken":7154,"endToken":7391,"text":"First Incremental Auction: \n \n“First Incremental Auction” shall mean an Incremental Auction conducted 20 months prior to the \nstart of the Delivery Year to which it relates. \n \nFlexible Resource:   \n“Flexible Resource” shall mean a generating resource that must have a combined Start-up Time \nand Notification Time of less than or equal to two hours; and a Minimum Run Time of less than \nor equal to two hours.   \nForecast Pool Requirement: \n \n“Forecast Pool Requirement” shall have the meaning specified in the Reliability Assurance \nAgreement.  \n \nForeign Guaranty: \n \n“Foreign Guaranty” shall mean a Corporate Guaranty provided by an Affiliate of a Participant \nthat is domiciled in a foreign country, and meets all of the provisions of Tariff, Attachment Q. \n \nForm 715 Planning Criteria: \n \n“Form 715 Planning Criteria” shall have the same meaning provided in the Operating \nAgreement. \n \nForward Daily Natural Gas Prices: \n \n“Forward Daily Natural Gas Prices” shall have the meaning provided in Tariff, Attachment DD, \nsection 5.10(a)(v-1)(E).  \n \nForward Hourly Ancillary Services Prices: \n \n“Forward Hourly Ancillary Services Prices” shall have the meaning provided in Tariff, \nAttachment DD, section 5.10(a)(v-1)(D).  \n \nForward Hourly LMPs:  \n \n“Forward Hourly LMPs” shall have the meaning provided in Tariff, Attachment DD, section \n5.10(a)(v-1)(C). \n \nFTR Credit Limit:  \n \n“FTR Credit Limit” shall mean the amount of credit established with PJMSettlement that an FTR \nParticipant has specifically designated to be used for FTR activity in a specific customer account."},{"page":23,"startToken":7391,"endToken":7732,"text":"Any such credit so set aside shall not be considered available to satisfy any other credit \nrequirement the FTR Participant may have with PJMSettlement. \n \nFTR Credit Requirement: \n \n“FTR Credit Requirement” shall mean the amount of credit that a Participant must provide in \norder to support the FTR positions that it holds and/or for which it is bidding.  The FTR Credit \nRequirement shall not include months for which the invoicing has already been completed, \nprovided that PJMSettlement shall have up to two Business Days following the date of the \ninvoice completion to make such adjustments in its credit systems.  FTR Credit Requirements \nare calculated and applied separately for each separate customer account. \n \nFTR Flow Undiversified: \n \n“FTR Flow Undiversified” shall have the meaning established in Tariff, Attachment Q, section \nVI.C.6. \n \nFTR Historical Value: \n  \nFor each FTR for each month, “FTR Historical Value” shall mean the weighted average of  \nhistorical values over three years for the FTR path using the following weightings:  50% - most \nrecent year; 30% - second year; 20% - third year.   \n \nFTR Holder: \n \n“FTR Holder” shall mean the PJM Member that has acquired and possesses an FTR. \n \nFTR Monthly Credit Requirement Contribution: \n \nFor each FTR, for each month, ”FTR Monthly Credit Requirement Contribution” shall mean the \ntotal FTR cost for the month, prorated on a daily basis, less the FTR Historical Value for the \nmonth.  For cleared FTRs, this contribution may be negative; prior to clearing, FTRs with \nnegative contribution shall be deemed to have zero contribution. \n \nFTR Net Activity: \n  \n“FTR Net Activity” shall mean the aggregate net value of the billing line items for auction \nrevenue rights credits, FTR auction charges, FTR auction credits, and FTR congestion credits, \nand shall also include day-ahead and balancing/real-time congestion charges up to a maximum \nnet value of the sum of the foregoing auction revenue rights credits, FTR auction charges, FTR \nauction credits and FTR congestion credits. \n \nFTR Participant: \n \n“FTR Participant” shall mean any Market Participant that provides or is required to provide \nCollateral in order to participate in PJM’s FTR market."},{"page":24,"startToken":7732,"endToken":7867,"text":"FTR Portfolio Auction Value: \n \n“FTR Portfolio Auction Value” shall mean for each customer account of a Market Participant, \nthe sum, calculated on a monthly basis, across all FTRs, of the FTR price times the FTR volume \nin MW.  \n \nFuel Cost Policy: \n \n“Fuel Cost Policy” shall mean the document provided by a Market Seller to PJM and the Market \nMonitoring Unit in accordance with PJM Manual 15 and Operating Agreement, Schedule 2, \nwhich documents the Market Seller’s method used to price fuel for calculation of the Market \nSeller’s cost-based offers for a generation resource.  \n \nFull Notice to Proceed: \n \n“Full Notice to Proceed” shall mean that all material third party contractors have been given the \nnotice to proceed with construction by the Capacity Market Seller or its agent, with a guaranteed \ncompletion date backed by liquidated damages."},{"page":25,"startToken":7867,"endToken":8208,"text":"Definitions – I – J - K \n \nIDR Transfer Agreement: \n \n“IDR Transfer Agreement” shall mean an agreement to transfer, subject to the terms of Tariff, \nPart VI, section 237, Incremental Deliverability Rights to a party for the purpose of eliminating \nor reducing the need for Local or Network Upgrades that would otherwise have been the \nresponsibility of the party receiving such rights. \n \nImmediate-need Reliability Project: \n \n“Immediate-need Reliability Project” shall have the same meaning provided in the Operating \nAgreement. \n \nInadvertent Interchange: \n \n“Inadvertent Interchange” shall mean the difference between net actual energy flow and net \nscheduled energy flow into or out of the individual Control Areas operated by PJM. \n \nIncidental Expenses: \n \n“Incidental Expenses” shall mean those expenses incidental to the performance of construction \npursuant to an Interconnection Construction Service Agreement, including, but not limited to, the \nexpense of temporary construction power, telecommunications charges, Interconnected \nTransmission Owner expenses associated with, but not limited to, document preparation, design \nreview, installation, monitoring, and construction-related operations and maintenance for the \nCustomer Facility and for the Interconnection Facilities. \n \nIncremental Auction: \n \n“Incremental Auction” shall mean any of several auctions conducted for a Delivery Year after \nthe Base Residual Auction for such Delivery Year and before the first day of such Delivery Year, \nincluding the First Incremental Auction, Second Incremental Auction, Third Incremental Auction \nor Conditional Incremental Auction.  Incremental Auctions (other than the Conditional \nIncremental Auction shall be held for the purposes of: \n \n \n(i) \nallowing Market Sellers that committed Capacity Resources in the Base Residual \nAuction for a Delivery Year, which subsequently are determined to be unavailable to deliver the \ncommitted Unforced Capacity in such Delivery Year (due to resource retirement, resource \ncancellation or construction delay, resource derating, EFORd increase, a decrease in the \nNominated Demand Resource Value of a Planned Demand Resource, delay or cancellation of a \nQualifying Transmission Upgrade, or similar occurrences) to submit Buy Bids for replacement \nCapacity Resources; and  \n \n(ii) \nallowing the Office of the Interconnection to reduce or increase the amount of \ncommitted capacity secured in prior auctions for such Delivery Year if, as a result of changed"},{"page":26,"startToken":8208,"endToken":8534,"text":"circumstances or expectations since the prior auction(s), there is, respectively, a significant \nexcess or significant deficit of committed capacity for such Delivery Year, for the PJM Region \nor for an LDA. \n \nIncremental Auction Revenue Rights: \n \n“Incremental Auction Revenue Rights” shall mean the additional Auction Revenue Rights, not \npreviously feasible, created by the addition of Incremental Rights-Eligible Required \nTransmission Enhancements, Merchant Transmission Facilities, or of one or more Customer-\nFunded Upgrades.  \n \nIncremental Available Transfer Capability Revenue Rights: \n \n“Incremental Available Transfer Capability Revenue Rights” shall mean the rights to revenues \nthat are derived from incremental Available Transfer Capability created by the addition of \nMerchant Transmission Facilities or of one of more Customer-Funded Upgrades. \n \nIncremental Capacity Transfer Right: \n \n“Incremental Capacity Transfer Right” shall mean a Capacity Transfer Right allocated to a \nGeneration Interconnection Customer or Transmission Interconnection Customer obligated to \nfund a transmission facility or upgrade, to the extent such upgrade or facility increases the \ntransmission import capability into a Locational Deliverability Area, or a Capacity Transfer \nRight allocated to a Responsible Customer in accordance with Tariff, Schedule 12A.  \n \nIncremental Deliverability Rights (IDRs): \n \n“Incremental Deliverability Rights” or “IDRs” shall mean the rights to the incremental ability, \nresulting from the addition of Merchant Transmission Facilities, to inject energy and capacity at \na point on the Transmission System, such that the injection satisfies the deliverability \nrequirements of a Capacity Resource. Incremental Deliverability Rights may be obtained by a \ngenerator or a Generation Interconnection Customer, pursuant to an IDR Transfer Agreement, to \nsatisfy, in part, the deliverability requirements necessary to obtain Capacity Interconnection \nRights. \n \nIncremental Energy Offer: \n \n“Incremental Energy Offer” shall mean the cost in dollars per MWh of providing an additional \nMWh from a synchronized unit. It consists primarily of the cost of fuel, as determined by the \nunit’s incremental heat rate (adjusted by the performance factor) times the fuel cost. It also \nincludes operating costs, Maintenance Adders, emissions allowances, tax credits, and energy \nmarket opportunity costs. \n \nIncremental Multi-Driver Project:"},{"page":27,"startToken":8534,"endToken":8848,"text":"“Incremental Multi-Driver Project” shall have the same meaning provided in the Operating \nAgreement. \n \nIncremental Rights-Eligible Required Transmission Enhancements: \n \n“Incremental Rights-Eligible Required Transmission Enhancements” shall mean Regional \nFacilities and Necessary Lower Voltage Facilities or Lower Voltage Facilities (as defined in \nTariff, Schedule 12) and meet one of the following criteria: (1) cost responsibility is assigned to \nnon-contiguous Zones that are not directly electrically connected; or (2) cost responsibility is \nassigned to Merchant Transmission Providers that are Responsible Customers. \n \nIncrement Offer: \n \n“Increment Offer” shall mean a type of Virtual Transaction that is an offer to sell energy at a \nspecified location in the Day-ahead Energy Market.  A cleared Increment Offer results in \nscheduled generation at the specified location in the Day-ahead Energy Market. \n \nIndependent Auditor: \n \n“Independent Auditor” shall mean an external accountant or external accounting firm who is not \nan employee of, not otherwise related to, not obligated to, has no interest in, and is independent \nin the performance of professional services for, the entity he/she/it is auditing, its management \nand/or its owners. \n \nInitial Operation: \n \n“Initial Operation” shall mean the commencement of operation of the Customer Facility and \nCustomer Interconnection Facilities after satisfaction of the conditions of Tariff, Attachment O- \nAppendix 2, section 1.4 (an Interconnection Service Agreement). \n \nInteger Relaxation: \n \n“Integer Relaxation” shall mean the process by which the commitment status variable for an \nEligible Fast-Start Resource is allowed to vary between zero and one, inclusive of zero and one, \nas further described in Tariff, Attachment K-Appendix, section 2.2. \n \nInterconnected Entity: \n \n“Interconnected Entity” shall mean either the Interconnection Customer or the Interconnected \nTransmission Owner; Interconnected Entities shall mean both of them. \n \nInterconnected Transmission Owner: \n \n“Interconnected Transmission Owner” shall mean the Transmission Owner to whose \ntransmission facilities or distribution facilities Customer Interconnection Facilities are, or as the \ncase may be, a Customer Facility is, being directly connected.  When used in an Interconnection"},{"page":28,"startToken":8848,"endToken":9126,"text":"Construction Service Agreement, the term may refer to a Transmission Owner whose facilities \nmust be upgraded pursuant to the Facilities Study, but whose facilities are not directly \ninterconnected with those of the Interconnection Customer. \n \nInterconnection Construction Service Agreement: \n \n“Interconnection Construction Service Agreement” shall mean the agreement entered into by an \nInterconnection Customer, Interconnected Transmission Owner and the Transmission Provider \npursuant to Tariff, Part VI, Subpart B and in the form set forth in Tariff, Attachment P, relating \nto construction of Attachment Facilities, Network Upgrades, and/or Local Upgrades and \ncoordination of the construction and interconnection of an associated Customer Facility.  A \nseparate Interconnection Construction Service Agreement will be executed with each \nTransmission Owner that is responsible for construction of any Attachment Facilities, Network \nUpgrades, or Local Upgrades associated with interconnection of a Customer Facility. \n \nInterconnection Customer: \n \n“Interconnection Customer” shall mean a Generation Interconnection Customer and/or a \nTransmission Interconnection Customer. \n \nInterconnection Facilities: \n \n“Interconnection Facilities” shall mean the Transmission Owner Interconnection Facilities and \nthe Customer Interconnection Facilities. \n \nInterconnection Feasibility Study: \n \n“Interconnection Feasibility Study” shall mean either a Generation Interconnection Feasibility \nStudy or Transmission Interconnection Feasibility Study. \n \nInterconnection Party: \n \n“Interconnection Party” shall mean a Transmission Provider, Interconnection Customer, or the \nInterconnected Transmission Owner. Interconnection Parties shall mean all of them. \n \nInterconnection Request: \n \n“Interconnection Request” shall mean a Generation Interconnection Request, a Transmission \nInterconnection Request and/or an IDR Transfer Agreement. \n \nInterconnection Service: \n \n“Interconnection Service” shall mean the physical and electrical interconnection of the Customer \nFacility with the Transmission System pursuant to the terms of Tariff, Part IV and Tariff, Part VI \nand the Interconnection Service Agreement entered into pursuant thereto by Interconnection \nCustomer, the Interconnected Transmission Owner and Transmission Provider."},{"page":29,"startToken":9126,"endToken":9421,"text":"Interconnection Service Agreement: \n \n“Interconnection Service Agreement” shall mean an agreement among the Transmission \nProvider, an Interconnection Customer and an Interconnected Transmission Owner regarding \ninterconnection under Tariff, Part IV and Tariff, Part VI. \n \nInterconnection Studies: \n \n“Interconnection Studies” shall mean the Interconnection Feasibility Study, the System Impact \nStudy, and the Facilities Study described in Tariff, Part IV and Tariff, Part VI. \n \nInterface Pricing Point: \n \n“Interface Pricing Point” shall have the meaning specified in Operating Agreement, Schedule 1, \nsection 2.6A, and the parallel provisions of Tariff, Attachment K-Appendix, section 2.6A. \n \nInterim Resource Adequacy Service: \n \n“Interim Resource Adequacy Service” shall mean a load reduction service through which New \nLarge Loads reduce load as directed by the applicable Electric Distributor in response to an \nInterim Resource Adequacy Service Action requested by the Office of the Interconnection. Such \nreductions in load may be eligible for compensation pursuant to Attachment DD-4, section X. \n \nInterim Resource Adequacy Service Action: \n \n“Interim Resource Adequacy Service Action” shall mean an Operating Instruction, as defined by \nNERC, issued from the Office of the Interconnection to reduce load prior to calling on Pre-\nEmergency Load Management Reductions after determining that available economic real-time \nsupply may not be sufficient to maintain reserves to meet applicable Reserve Requirements \nand/or Interconnection Reliability Operating Limits within prescribed limits and prevent \ncascading outages. \n \nIntermittent Resource: \n \n“Intermittent Resource” shall mean a Generation Capacity Resource with output that can vary as \na function of its energy source, such as wind, solar, run of river hydroelectric power and other \nrenewable resources.  \n \nInternal Credit Score: \n \n“Internal Credit Score” shall mean a composite numerical score determined by PJMSettlement \nusing quantitative and qualitative metrics to estimate various predictors of a credit event \nhappening to a Market Participant that may trigger a credit event. \n \nInternal Market Buyer:"},{"page":30,"startToken":9421,"endToken":9769,"text":"“Internal Market Buyer” shall mean a Market Buyer making purchases of energy from the PJM \nInterchange Energy Market for ultimate consumption by end-users inside the PJM Region that \nare served by Network Transmission Service. \n \nInterregional Transmission Project: \n \n“Interregional Transmission Project” shall mean transmission facilities that would be located \nwithin two or more neighboring transmission planning regions and are determined by each of \nthose regions to be a more efficient or cost effective solution to regional transmission needs. \n \nInterruption: \n \n“Interruption” shall mean a reduction in non-firm transmission service due to economic reasons \npursuant to Tariff, Part II, section 14.7. \n \nIROL Critical Resource: \n \n“IROL Critical Resource” shall mean a generation resource that the Office of the Interconnection \ndesignates, pursuant to NERC Reliability Standards, as having an interconnection reliability \noperating limit that, if violated, could lead to instability, uncontrolled separation, or cascading \noutages that adversely impact the reliability of the bulk electric system.   \n \nJointly Owned Cross-Subsidized Capacity Resource: \n \n“Jointly Owned Cross-Subsidized Capacity Resource” shall mean a Capacity Resource that is \nsupported by a facility that is jointly owned, where at least one owner is entitled to or receives a \nState Subsidy associated with such Capacity Resource, and therefore shall be considered a \nCapacity Resource with State Subsidy; provided however, in the event that the material rights \nand obligations of such generating facility are in pari passu, meaning that such rights and \nobligations are allocated among the owners pro rata based on ownership share, only Capacity \nResources of those owners entitled to receive or receiving a State Subsidy shall have their share \nof such resource considered a Capacity Resource with a State Subsidy and Capacity Resources of \nowners not entitled to a State Subsidy shall not be considered a Capacity Resource with a State \nSubsidy.  Each of these designations may be overcome by either Capacity Market Seller \ndemonstrating to the Office of Interconnection, with advice and input from the Market \nMonitoring Unit, that there is no cross-subsidization or the Office of the Interconnection, with \nreview and input from the Market Monitor, finds based on sufficient evidence, that there is cross-\nsubsidization."},{"page":31,"startToken":9769,"endToken":10238,"text":"Definitions – L – M – N \n \nLarge Load: \n \n“Large Load” shall have the meaning provided in the Reliability Assurance Agreement. \n \nLegacy Policy: \n \n“Legacy Policy” shall mean any legislative, executive, or regulatory action that specifically \ndirects a payment outside of PJM Markets to a designated or prospective Generation Capacity \nResource and the enactment of such action predates October 1, 2021, regardless of when any \nimplementing governmental action to effectuate the action to direct payment outside of PJM \nMarkets occurs. \n \nLimited Demand Resource:  \n \n“Limited Demand Resource” shall have the meaning specified in the Reliability Assurance \nAgreement. \n \nLimited Demand Resource Reliability Target:  \n \n“Limited Demand Resource Reliability Target” for the PJM Region or an LDA, shall mean the \nmaximum amount of Limited Demand Resources determined by PJM to be consistent with the \nmaintenance of reliability, stated in Unforced Capacity that shall be used to calculate the \nMinimum Extended Summer Demand Resource Requirement for Delivery Years through May \n31, 2017 and the Limited Resource Constraint for the 2017/2018 and 2018/2019 Delivery Years \nfor the PJM Region or such LDA.  As more fully set forth in the PJM Manuals, PJM calculates \nthe Limited Demand Resource Reliability Target by first:  i) testing the effects of the ten-\ninterruption requirement by comparing possible loads on peak days under a range of weather \nconditions (from the daily load forecast distributions for the Delivery Year in question) against \npossible generation capacity on such days under a range of conditions (using the cumulative \ncapacity distributions employed in the Installed Reserve Margin study for the PJM Region and in \nthe Capacity Emergency Transfer Objective study for the relevant LDAs for such Delivery Year) \nand, by varying the assumed amounts of DR that is committed and displaces committed \ngeneration, determines the DR penetration level at which there is a ninety percent probability \nthat DR will not be called (based on the applicable operating reserve margin for the PJM Region \nand for the relevant LDAs) more than ten times over those peak days;  ii) testing the six-hour \nduration requirement by calculating the MW difference between the highest hourly unrestricted \npeak load and seventh highest hourly unrestricted peak load on certain high peak load days (e.g., \nthe annual peak, loads above the weather normalized peak, or days where load management was \ncalled) in recent years, then dividing those loads by the forecast peak for those years and \naveraging the result; and (iii) (for the 2016/2017 and 2017/2018 Delivery Years) testing the \neffects of the six-hour duration requirement by comparing possible hourly loads on peak days \nunder a range of weather conditions (from the daily load forecast distributions for the Delivery \nYear in question) against possible generation capacity on such days under a range of conditions \n(using a Monte Carlo model of hourly capacity levels that is consistent with the capacity model"},{"page":32,"startToken":10238,"endToken":10712,"text":"employed in the Installed Reserve Margin study for the PJM Region and in the Capacity \nEmergency Transfer Objective study for the relevant LDAs for such Delivery Year) and, by \nvarying the assumed amounts of DR that is committed and displaces committed generation, \ndetermines the DR penetration level at which there is a ninety percent probability that DR will \nnot be called (based on the applicable operating reserve margin for the PJM Region and for the \nrelevant LDAs) for more than six hours over any one or more of the tested peak days.  Second, \nPJM adopts the lowest result from these three tests as the Limited Demand Resource Reliability \nTarget.  The Limited Demand Resource Reliability Target shall be expressed as a percentage of \nthe forecasted peak load of the PJM Region or such LDA and is converted to Unforced Capacity \nby multiplying [the reliability target percentage] times [the Forecast Pool Requirement] times \n[the DR Factor] times [the forecasted peak load of the PJM Region or such LDA, reduced by the \namount of load served under the FRR Alternative]. \n \nLimited Resource Constraint: \n \n“Limited Resource Constraint” shall mean, for the 2017/2018 Delivery Year and for FRR \nCapacity Plans the 2017/2018 and Delivery Years, for the PJM Region or each LDA for which \nthe Office of the Interconnection is required under Tariff, Attachment DD, section 5.10(a) to \nestablish a separate VRR Curve for a Delivery Year, a limit on the total amount of Unforced \nCapacity that can be committed as Limited Demand Resources for the 2017/2018 Delivery Year \nin the PJM Region or in such LDA, calculated as the Limited Demand Resource Reliability \nTarget for the PJM Region or such LDA, respectively, minus the Short Term Resource \nProcurement Target for the PJM Region or such LDA, respectively. \n \nLimited Resource Price Decrement: \n“Limited Resource Price Decrement” shall mean, for the 2017/2018 Delivery Year, a difference \nbetween the clearing price for Limited Demand Resources and the clearing price for Extended \nSummer Demand Resources and Annual Resources, representing the cost to procure additional \nExtended Summer Demand Resources or Annual Resources out of merit order when the Limited \nResource Constraint is binding. \n \nList of Approved Contractors: \n \n“List of Approved Contractors” shall mean a list developed by each Transmission Owner and \npublished in a PJM Manual of (a) contractors that the Transmission Owner considers to be \nqualified to install or construct new facilities and/or upgrades or modifications to existing \nfacilities on the Transmission Owner’s system, provided that such contractors may include, but \nneed not be limited to, contractors that, in addition to providing construction services, also \nprovide design and/or other construction-related services, and (b) manufacturers or vendors of \nmajor transmission-related equipment (e.g., high-voltage transformers, transmission line, circuit \nbreakers) whose products the Transmission Owner considers acceptable for installation and use \non its system. \n \nLoad Interest:"},{"page":33,"startToken":10712,"endToken":10978,"text":"“Load Interest” shall mean, for the purposes of the minimum offer price rule, responsibility for \nserving load within the PJM Region, whether by the Capacity Market Seller, an affiliate of the \nCapacity Market Seller, or by an entity with which the Capacity Market Seller is in contractual \nprivity with respect to the subject Generation Capacity Resource. \n \nLoad Management: \n \n“Load Management” shall mean a Demand Resource (“DR”) as defined in the Reliability \nAssurance Agreement. \n \nLoad Management Event: \n \n“Load Management Event” shall mean a) a single temporally contiguous dispatch of Demand \nResources in a Compliance Aggregation Area during an Operating Day, or b) multiple dispatches \nof Demand Resources in a Compliance Aggregation Area during an Operating Day that are \ntemporally contiguous.  \n \nLoad Ratio Share: \n \n“Load Ratio Share” shall mean the ratio of a Transmission Customer’s Network Load to the \nTransmission Provider’s total load. \n \nLoad Reduction Event: \n \n“Load Reduction Event” shall mean a reduction in demand by a Member or Special Member for \nthe purpose of participating in the PJM Interchange Energy Market. \n \nLoad Serving Charging Energy:  \n \n“Load Serving Charging Energy” shall mean energy that is purchased from the PJM Interchange \nEnergy Market and stored in an Energy Storage Resource or Open-Loop Hybrid Resource for \nlater resale to end-use load. \n \nLoad Serving Entity (LSE): \n \n“Load Serving Entity” or “LSE” shall have the meaning specified in the Reliability Assurance \nAgreement. \n \nLoad Shedding: \n \n“Load Shedding” shall mean the systematic reduction of system demand by temporarily \ndecreasing load in response to transmission system or area capacity shortages, system instability, \nor voltage control considerations under Tariff, Part II or Part III. \n \nLocal Upgrades:"},{"page":34,"startToken":10978,"endToken":11371,"text":"“Local Upgrades” shall mean modifications or additions of facilities to abate any local thermal \nloading, voltage, short circuit, stability or similar engineering problem caused by the \ninterconnection and delivery of generation to the Transmission System.  Local Upgrades shall \ninclude: \n \n \n(i) Direct Connection Local Upgrades which are Local Upgrades that only serve the \nCustomer Interconnection Facility and have no impact or potential impact on the Transmission \nSystem until the final tie-in is complete; and  \n \n \n(ii) Non-Direct Connection Local Upgrades which are parallel flow Local Upgrades that \nare not Direct Connection Local Upgrades. \n \nLocation: \n \n“Location” as used in the Economic Load Response rules shall mean an end-use customer site as \ndefined by the relevant electric distribution company account number. \n \nLOC Deviation:   \n \n“LOC Deviation,” shall mean, for units other than wind units, the LOC Deviation shall equal the \ndesired megawatt amount for the resource determined according to the point on the Final Offer \ncurve corresponding to the Real-time Settlement Interval real-time Locational Marginal Price at \nthe resource’s bus and adjusted for any reduction in megawatts due to Regulation, Synchronized \nReserve, or Secondary Reserve assignments and limited to the lesser of the unit’s Economic \nMaximum or the unit’s Generation Resource Maximum Output, minus the actual output of the \nunit.  For wind units, the LOC Deviation shall mean the deviation of the generating unit’s output \nequal to the lesser of the PJM forecasted output for the unit or the desired megawatt amount for \nthe resource determined according to the point on the Final Offer curve corresponding to the \nReal-time Settlement Interval integrated real-time Locational Marginal Price at the resource’s \nbus, and shall be limited to the lesser of the unit’s Economic Maximum or the unit’s Generation \nResource Maximum Output, minus the actual output of the unit. \n \nLocational Deliverability Area (LDA): \n \n“Locational Deliverability Area” or “LDA” shall mean a geographic area within the PJM Region \nthat has limited transmission capability to import capacity to satisfy such area’s reliability \nrequirement, as determined by the Office of the Interconnection in connection with preparation \nof the Regional Transmission Expansion Plan, and as specified in Reliability Assurance \nAgreement, Schedule 10.1. \n \nLocational Deliverability Area Reliability Requirement: \n \n“Locational Deliverability Area Reliability Requirement” shall mean the projected internal \ncapacity in the Locational Deliverability Area plus the Capacity Emergency Transfer Objective \nfor the Delivery Year, as determined by the Office of the Interconnection in connection with"},{"page":35,"startToken":11371,"endToken":11639,"text":"preparation of the Regional Transmission Expansion Plan, less the minimum internal resources \nrequired for all FRR Entities in such Locational Deliverability Area. \n \nLocational Price Adder: \n \n“Locational Price Adder” shall mean an addition to the marginal value of Unforced Capacity \nwithin an LDA as necessary to reflect the price of Capacity Resources required to relieve \napplicable binding locational constraints.  \n \nLocational Reliability Charge: \n \n“Locational Reliability Charge” shall have the meaning specified in the Reliability Assurance \nAgreement.  \n \nLocational UCAP: \n \n“Locational UCAP” shall mean unforced capacity that a Member with available uncommitted \ncapacity sells in a bilateral transaction to a Member that previously committed capacity through \nan RPM Auction but now requires replacement capacity to fulfill its RPM Auction commitment.  \nThe Locational UCAP Seller retains responsibility for performance of the resource providing \nsuch replacement capacity.   \n \nLocational UCAP Seller: \n \n“Locational UCAP Seller” shall mean a Member that sells Locational UCAP. \n \nLong-lead Project: \n \n“Long-lead Project” shall have the same meaning provided in the Operating Agreement. \n \nLong-Term Firm Point-To-Point Transmission Service: \n \n“Long-Term Firm Point-To-Point Transmission Service” shall mean firm Point-To-Point \nTransmission Service under Tariff, Part II with a term of one year or more. \n \nLoss Price: \n \n“Loss Price” shall mean the loss component of the Locational Marginal Price, which is the effect \non transmission loss costs (whether positive or negative) associated with increasing the output of \na generation resource or decreasing the consumption by a Demand Resource based on the effect \nof increased generation from or consumption by the resource on transmission losses, calculated \nas specified in Operating Agreement, Schedule 1, section 2, and the parallel provisions of Tariff, \nAttachment K-Appendix, section 2. \n \nM2M Flowgate:"},{"page":36,"startToken":11639,"endToken":11944,"text":"“M2M Flowgate” shall have the meaning provided in the Joint Operating Agreement between \nthe Midcontinent Independent Transmission System Operator, Inc. and PJM Interconnection, \nL.L.C. \n \nMaintenance Adder:   \n \n“Maintenance Adder” shall mean an adder that may be included to account for variable operation \nand maintenance expenses in a Market Seller’s Fuel Cost Policy.  The Maintenance Adder is \ncalculated in accordance with the applicable provisions of PJM Manual 15, and may only include \nexpenses incurred as a result of electric production. \n \nManual Load Dump Action: \n \n“Manual Load Dump Action” shall mean an Operating Instruction, as defined by NERC, from \nPJM to shed firm load when the PJM Region cannot provide adequate capacity to meet the PJM \nRegion’s load and tie schedules, or to alleviate critically overloaded transmission lines or other \nequipment. \n \nManual Load Dump Warning: \n \n“Manual Load Dump Warning” shall mean a notification from PJM to warn Members of an \nincreasingly critical condition of present operations that may require manually shedding load. \n \nMarginal Value:  \n \n“Marginal Value” shall mean the incremental change in system dispatch costs, measured as a \n$/MW value incurred by providing one additional MW of relief to the transmission constraint. \n \nMarket Monitor: \n \n“Market Monitor” means the head of the Market Monitoring Unit. \n \nMarket Monitoring Unit or MMU: \n \n“Market Monitoring Unit” or “MMU” means the independent Market Monitoring Unit defined in \n18 CFR § 35.28(a)(7) and established under the PJM Market Monitoring Plan (Attachment M) to \nthe PJM Tariff that is responsible for implementing the Market Monitoring Plan, including the \nMarket Monitor.  The Market Monitoring Unit may also be referred to as the IMM or \nIndependent Market Monitor for PJM \n \nMarket Monitoring Unit Advisory Committee or MMU Advisory Committee: \n \n“Market Monitoring Unit Advisory Committee” or “MMU Advisory Committee” shall mean the \ncommittee established under Tariff, Attachment M, section III.H. \n \nMarket Operations Center:"},{"page":37,"startToken":11944,"endToken":12309,"text":"“Market Operations Center” shall mean the equipment, facilities and personnel used by or on \nbehalf of a Market Participant to communicate and coordinate with the Office of the \nInterconnection in connection with transactions in the PJM Interchange Energy Market or the \noperation of the PJM Region. \n \nMarket Participant: \n \n“Market Participant” shall mean a Market Buyer, a Market Seller, an Economic Load Response \nParticipant, or all three, except when such term is used in Tariff, Attachment M, in which case \nMarket Participant shall mean an entity that generates, transmits, distributes, purchases, or sells \nelectricity, ancillary services, or any other product or service provided under the PJM Tariff or \nOperating Agreement within, into, out of, or through the PJM Region, but it shall not include an \nAuthorized Government Agency that consumes energy for its own use but does not purchase or \nsell energy at wholesale. \n \nMarket Participant Energy Injection: \n \n“Market Participant Energy Injection” shall mean transactions in the Day-ahead Energy Market \nand Real-time Energy Market, including but not limited to Day-ahead generation schedules, real-\ntime generation output, Increment Offers, internal bilateral transactions and import transactions, \nas further described in the PJM Manuals.  \n \nMarket Participant Energy Withdrawal: \n \n“Market Participant Energy Withdrawal” shall mean transactions in the Day-ahead Energy \nMarket and Real-time Energy Market, including but not limited to Demand Bids, Decrement \nBids, real-time load (net of Behind The Meter Generation expected to be operating, but not to be \nless than zero), internal bilateral transactions and Export Transactions, as further described in the \nPJM Manuals.  \n \nMarket Revenue Neutrality Offset:  \n \n“Market Revenue Neutrality Offset” shall mean the revenue in excess of the cost for a resource \nfrom the energy, Synchronized Reserve, Non-Synchronized Reserve, and Secondary Reserve \nmarkets realized from an increase in real-time market megawatt assignment from a day-ahead \nmarket megawatt assignment in any of these markets due to the decrease in the real-time reserve \nmarket megawatt assignment from a day-ahead reserve market megawatt assignment in any of \nthe reserve markets. \n \nMarket Seller Offer Cap: \n \n“Market Seller Offer Cap” shall mean a maximum offer price applicable to certain Market \nSellers under certain conditions, as determined in accordance with Tariff, Attachment DD. \nsection 6 and Tariff, Attachment M-Appendix, section II.E."},{"page":38,"startToken":12309,"endToken":12665,"text":"Market Violation: \n \n“Market Violation” shall mean a tariff violation, violation of a Commission-approved order, rule \nor regulation, market manipulation, or inappropriate dispatch that creates substantial concerns \nregarding unnecessary market inefficiencies, as defined in 18 C.F.R. § 35.28(b)(8). \n \nMaterial Modification: \n \n“Material Modification” shall mean any modification to an Interconnection Request that has a \nmaterial adverse effect on the cost or timing of Interconnection Studies related to, or any \nNetwork Upgrades or Local Upgrades needed to accommodate, any Interconnection Request \nwith a later Queue Position. \n \nMaximum Daily Starts: \n \n“Maximum Daily Starts” shall mean the maximum number of times that a generating unit can be \nstarted in an Operating Day under normal operating conditions. \n \nMaximum Emergency: \n \n“Maximum Emergency” shall mean the designation of all or part of the output of a generating \nunit for which the designated output levels may require extraordinary procedures and therefore \nare available to the Office of the Interconnection only when the Office of the Interconnection \ndeclares a Maximum Generation Emergency and requests generation designated as Maximum \nEmergency to run.  The Office of the Interconnection shall post on the PJM website the \naggregate amount of megawatts that are classified as Maximum Emergency. \n \nMaximum Facility Output: \n \n“Maximum Facility Output” shall mean the maximum (not nominal) net electrical power output \nin megawatts, specified in the Interconnection Service Agreement, after supply of any parasitic \nor host facility loads, that a Generation Interconnection Customer’s Customer Facility is \nexpected to produce, provided that the specified Maximum Facility Output shall not exceed the \noutput of the proposed Customer Facility that Transmission Provider utilized in the System \nImpact Study. \n \nMaximum Generation Emergency: \n \n“Maximum Generation Emergency” shall mean an Emergency declared by the Office of the \nInterconnection to address either a generation or transmission emergency in which the Office of \nthe Interconnection anticipates requesting one or more Generation Capacity Resources, or Non-\nRetail Behind The Meter Generation resources to operate at its maximum net or gross electrical \npower output, subject to the equipment stress limits for such Generation Capacity Resource or \nNon-Retail Behind The Meter resource in order to manage, alleviate, or end the Emergency. \n \nMaximum Generation Emergency Alert:"},{"page":39,"startToken":12665,"endToken":12950,"text":"“Maximum Generation Emergency Alert” shall mean an alert issued by the Office of the \nInterconnection to notify PJM Members, Transmission Owners, resource owners and operators, \ncustomers, and regulators that a Maximum Generation Emergency may be declared, for any \nOperating Day in either, as applicable, the Day-ahead Energy Market or the Real-time Energy \nMarket, for all or any part of such Operating Day. \n \nMaximum Run Time: \n \n“Maximum Run Time” shall mean the maximum number of hours a generating unit can run over \nthe course of an Operating Day, as measured by PJM’s State Estimator. \n \nMaximum State of Charge: \n \n“Maximum State of Charge” shall mean the maximum State of Charge that should not be \nexceeded, measured in units of megawatt-hours. \n \nMaximum Weekly Starts: \n \n“Maximum Weekly Starts” shall mean the maximum number of times that a generating unit can \nbe started in one week, defined as the 168 hour period starting Monday 0001 hour, under normal \noperating conditions. \n \nMember: \n  \n“Member” shall have the meaning provided in the Operating Agreement. \n \nMerchant A.C. Transmission Facilities: \n \n“Merchant A.C. Transmission Facility” shall mean Merchant Transmission Facilities that are \nalternating current (A.C.) transmission facilities, other than those that are Controllable A.C. \nMerchant Transmission Facilities.  \n \nMerchant D.C. Transmission Facilities: \n \n“Merchant D.C. Transmission Facilities” shall mean direct current (D.C.) transmission facilities \nthat are interconnected with the Transmission System pursuant to Tariff, Part IV and Part VI.  \n \nMerchant Network Upgrades: \n \n“Merchant Network Upgrades” shall mean additions to, or modifications or replacements of, \nphysical facilities of the Interconnected Transmission Owner that, on the date of the pertinent \nTransmission Interconnection Customer’s Upgrade Request, are part of the Transmission System \nor are included in the Regional Transmission Expansion Plan. \n \nMerchant Transmission Facilities:"},{"page":40,"startToken":12950,"endToken":13395,"text":"“Merchant Transmission Facilities” shall mean A.C. or D.C. transmission facilities that are \ninterconnected with or added to the Transmission System pursuant to Tariff, Part IV and Part VI \nand that are so identified in Tariff, Attachment T, provided, however, that Merchant \nTransmission Facilities shall not include (i) any Customer Interconnection Facilities, (ii) any \nphysical facilities of the Transmission System that were in existence on or before March 20, \n2003 ; (iii) any expansions or enhancements of the Transmission System that are not identified as \nMerchant Transmission Facilities in the Regional Transmission Expansion Plan and Attachment \nT to the Tariff, or (iv) any transmission facilities that are included in the rate base of a public \nutility and on which a regulated return is earned. \n \nMerchant Transmission Provider: \n \n“Merchant Transmission Provider” shall mean an Interconnection Customer that (1) owns,  \ncontrols, or controls the rights to use the transmission capability of, Merchant D.C. Transmission \nFacilities and/or Controllable A.C. Merchant Transmission Facilities that connect the \nTransmission System with another control area, (2) has elected to receive Transmission Injection \nRights and Transmission Withdrawal Rights associated with such facility pursuant to Tariff, Part \nIV, section 36, and (3) makes (or will make) the transmission capability of such facilities \navailable for use by third parties under terms and conditions approved by the Commission and \nstated in the Tariff, consistent with Tariff, section 38. \n \nMetering Equipment: \n \n“Metering Equipment” shall mean all metering equipment installed at the metering points \ndesignated in the appropriate appendix to an Interconnection Service Agreement. \n \nMinimum Annual Resource Requirement: \n \n“Minimum Annual Resource Requirement” shall mean, for Delivery Years through May 31, \n2017,   the minimum amount of capacity that PJM will seek to procure from Annual Resources \nfor the PJM Region and for each Locational Deliverability Area for which the Office of the \nInterconnection is required under Tariff, Attachment DD, section 5.10(a) to establish a separate \nVRR Curve for such Delivery Year.  For the PJM Region, the Minimum Annual Resource \nRequirement shall be equal to the RTO Reliability Requirement minus [the Sub-Annual \nResource Reliability Target for the RTO in Unforced Capacity].  For an LDA, the Minimum \nAnnual Resource Requirement shall be equal to the LDA Reliability Requirement minus [the \nLDA CETL] minus [the Sub-Annual Resource Reliability Target for such LDA in Unforced \nCapacity]. The LDA CETL may be adjusted pro rata for the amount of load served under the \nFRR Alternative. \n \nMinimum Down Time: \n \nFor all generating units that are not combined cycle units, “Minimum Down Time” shall mean \nthe minimum number of hours under normal operating conditions between unit shutdown and \nunit startup, calculated as the shortest time difference between the unit’s generator breaker"},{"page":41,"startToken":13395,"endToken":13856,"text":"opening and after the unit’s generator breaker closure, which is typically indicated by \ntelemetered or aggregated State Estimator megawatts greater than zero. For combined cycle \nunits, “Minimum Down Time” shall mean the minimum number of hours between the last \ngenerator breaker opening and after first combustion turbine generator breaker closure, which is \ntypically indicated by telemetered or aggregated State Estimator megawatts greater than zero. \n \nMinimum Extended Summer Resource Requirement: \n \n“Minimum Extended Summer Resource Requirement” shall mean, for Delivery Years through \nMay 31, 2017, the minimum amount of capacity that PJM will seek to procure from Extended \nSummer Demand Resources and Annual Resources for the PJM Region and for each Locational \nDeliverability Area for which the Office of the Interconnection is required under Tariff, \nAttachment DD, section 5.10(a) to establish a separate VRR Curve for such Delivery Year.  For \nthe PJM Region, the Minimum Extended Summer Resource Requirement shall be equal to the \nRTO Reliability Requirement minus [the Limited Demand Resource Reliability Target for the \nPJM Region in Unforced Capacity].  For an LDA, the Minimum Extended Summer Resource \nRequirement shall be equal to the LDA Reliability Requirement minus [the LDA CETL] minus \n[the Limited Demand Resource Reliability Target for such LDA in Unforced Capacity].  The \nLDA CETL may be adjusted pro rata for the amount of load served under the FRR Alternative. \n \nMinimum Generation Emergency: \n \n“Minimum Generation Emergency” shall mean an Emergency declared by the Office of the \nInterconnection in which the Office of the Interconnection anticipates requesting one or more \ngenerating resources to operate at or below Normal Minimum Generation, in order to manage, \nalleviate, or end the Emergency. \n \nMinimum Participation Requirements: \n \n“Minimum Participation Requirements” shall mean a set of minimum training, risk management, \ncommunication and capital or collateral requirements required for Participants in the PJM \nMarkets, as set forth herein and in the Form of Annual Certification set forth as Tariff, \nAttachment Q, Appendix 1.  Participants transacting in FTRs in certain circumstances will be \nrequired to demonstrate additional risk management procedures and controls as further set forth \nin the Annual Certification found in Tariff, Attachment Q, Appendix 1. \n \nMinimum Run Time: \n \nFor all generating units that are not combined cycle units, “Minimum Run Time” shall mean the \nminimum number of hours a unit must run, in real-time operations, from the time after generator \nbreaker closure, which is typically indicated by telemetered or aggregated State Estimator \nmegawatts greater than zero, to the time of generator breaker opening, as measured by PJM's \nState Estimator. For combined cycle units, “Minimum Run Time” shall mean the time period \nafter the first combustion turbine generator breaker closure, which is typically indicated by \ntelemetered or aggregated State Estimator megawatts greater than zero, and the last generator \nbreaker opening as measured by PJM’s State Estimator."},{"page":42,"startToken":13856,"endToken":14155,"text":"Minimum State of Charge: \n \n“Minimum State of Charge” shall mean the minimum State of Charge that should be maintained \nin units of megawatt-hours. \n \nMISO: \n \n“MISO” shall mean the Midcontinent Independent System Operator, Inc. or any successor \nthereto. \n \nMixed Technology Facility: \n \n“Mixed Technology Facility” shall mean a facility composed of distinct generation and/or \nelectric storage technology types behind the same Point of Interconnection.  Co-Located \nResources and Hybrid Resources form all or part of Mixed Technology Facilities. \n \nMOPR Floor Offer Price: \n \n“MOPR Floor Offer Price” shall mean a minimum offer price applicable to certain Market \nSeller’s Capacity Resources under certain conditions, as determined in accordance with Tariff, \nAttachment DD, sections 5.14(h), 5.14(h-1), and 5.14(h-2). \n \nMulti-Driver Project: \n \n“Multi-Driver Project” shall have the same meaning provided in the Operating Agreement. \n \nNative Load Customers: \n \n“Native Load Customers” shall mean the wholesale and retail power customers of a \nTransmission Owner on whose behalf the Transmission Owner, by statute, franchise, regulatory \nrequirement, or contract, has undertaken an obligation to construct and operate the Transmission \nOwner’s system to meet the reliable electric needs of such customers. \n \nNear-Term Transmission Service: \n \n“Near-Term Transmission Service” shall mean Transmission Service which ends not more than \n10 days after the Transmission Service request date.  When the description of obligations below \nrefers to either a request for information about the availability of potential Transmission Service \n(including, but not limited to, a request for ATC), or to the posting of ATC or other information \nrelated to potential service, the date that the information is requested or posted will serve as the \nTransmission Service request date.  “Near-Term Transmission Service” includes any Point-To-\nPoint Transmission Service and Network Integration Transmission Service where the start and \nend date of the designation or request is within the next 10 days. \n \nNERC:"},{"page":43,"startToken":14155,"endToken":14446,"text":"“NERC” shall mean the North American Electric Reliability Corporation or any successor \nthereto. \n \nNERC Interchange Distribution Calculator: \n \n“NERC Interchange Distribution Calculator” shall mean the NERC mechanism that is in effect \nand being used to calculate the distribution of energy, over specific transmission interfaces, from \nenergy transactions. \n \nNet Benefits Test:  \n \n“Net Benefits Test” shall mean a calculation to determine whether the benefits of a reduction in \nprice resulting from the dispatch of Economic Load Response exceeds the cost to other loads \nresulting from the billing unit effects of the load reduction, as specified in Operating Agreement, \nSchedule 1, section 3.3A.4 and the parallel provisions of Tariff, Attachment K-Appendix, section \n3.3A.4. \n \nNet Cost of New Entry:   \n \n“Net Cost of New Entry” shall mean the Cost of New Entry minus the Net Energy and Ancillary \nService Revenue Offset. \n \nNet Obligation: \n  \n“Net Obligation” shall mean the amount owed to PJMSettlement and PJM for purchases from the \nPJM Markets, Transmission Service, (under Tariff, Parts II and III , and other services pursuant \nto the Agreements, after applying a deduction for amounts owed to a Participant by \nPJMSettlement as it pertains to monthly market activity and services.  Should other markets be \nformed such that Participants may incur future Obligations in those markets, then the aggregate \namount of those Obligations will also be added to the Net Obligation. \n \nNet Sell Position: \n  \n“Net Sell Position” shall mean the amount of Net Obligation when Net Obligation is negative. \n \nNetwork Customer: \n \n“Network Customer” shall mean an entity receiving transmission service pursuant to the terms of \nthe Transmission Provider’s Network Integration Transmission Service under Tariff, Part III. \n \nNetwork External Designated Transmission Service: \n \n“Network External Designated Transmission Service” shall have the meaning set forth in \nReliability Assurance Agreement, Article I."},{"page":44,"startToken":14446,"endToken":14780,"text":"Network Integration Transmission Service: \n \n“Network Integration Transmission Service” shall mean the transmission service provided under \nTariff, Part III. \n \nNetwork Load: \n \n“Network Load” shall mean the load that a Network Customer designates for Network \nIntegration Transmission Service under Tariff, Part III.  The Network Customer’s Network Load \nshall include all load (including losses, Non-Dispatched Charging Energy, and Load Serving \nCharging Energy) served by the output of any Network Resources designated by the Network \nCustomer.  A Network Customer may elect to designate less than its total load as Network Load \nbut may not designate only part of the load at a discrete Point of Delivery.  Where an Eligible \nCustomer has elected not to designate a particular load at discrete points of delivery as Network \nLoad, the Eligible Customer is responsible for making separate arrangements under Tariff, Part \nII for any Point-To-Point Transmission Service that may be necessary for such non-designated \nload.  Network Load shall not include Dispatched Charging Energy. \n \nNetwork Operating Agreement: \n \n“Network Operating Agreement” shall mean an executed agreement that contains the terms and \nconditions under which the Network Customer shall operate its facilities and the technical and \noperational matters associated with the implementation of Network Integration Transmission \nService under Tariff, Part III. \n \nNetwork Operating Committee: \n \n“Network Operating Committee” shall mean a group made up of representatives from the \nNetwork Customer(s) and the Transmission Provider established to coordinate operating criteria \nand other technical considerations required for implementation of Network Integration \nTransmission Service under Tariff, Part III.  \n \nNetwork Resource: \n \n“Network Resource” shall mean any designated generating resource owned, purchased, or leased \nby a Network Customer under the Network Integration Transmission Service Tariff.  Network \nResources do not include any resource, or any portion thereof, that is committed for sale to third \nparties or otherwise cannot be called upon to meet the Network Customer’s Network Load on a \nnon-interruptible basis, except for purposes of fulfilling obligations under a reserve sharing \nprogram. \n \nNetwork Service User: \n \n“Network Service User” shall mean an entity using Network Transmission Service. \n \nNetwork Transmission Service:"},{"page":45,"startToken":14780,"endToken":15245,"text":"“Network Transmission Service” shall mean transmission service provided pursuant to the rates, \nterms and conditions set forth in Tariff, Part III, or transmission service comparable to such \nservice that is provided to a Load Serving Entity that is also a Transmission Owner. \n \nNetwork Upgrades: \n \n“Network Upgrades” shall mean modifications or additions to transmission-related facilities that \nare integrated with and support the Transmission Provider’s overall Transmission System for the \ngeneral benefit of all users of such Transmission System. Network Upgrades shall include: \n \n \n(i) Direct Connection Network Upgrades which are Network Upgrades that are not part \nof an Affected System; only serve the Customer Interconnection Facility; and have no impact or \npotential impact on the Transmission System until the final tie-in is complete.  Both \nTransmission Provider and Interconnection Customer must agree as to what constitutes Direct \nConnection Network Upgrades and identify them in the Interconnection Construction Service \nAgreement, Schedule D.  If the Transmission Provider and Interconnection Customer disagree \nabout whether a particular Network Upgrade is a Direct Connection Network Upgrade, the \nTransmission Provider must provide the Interconnection Customer a written technical \nexplanation outlining why the Transmission Provider does not consider the Network Upgrade to \nbe a Direcct Connection Network Upgrade within 15 days of its determination. \n \n \n(ii) Non-Direct Connection Network Upgrades which are parallel flow Network \nUpgrades that are not Direct Connection Network Upgrades. \n \nNeutral Party: \n \n“Neutral Party” shall have the meaning provided in Tariff, Part I, section 9.3(v). \n \nNew Entry Capacity Resource with State Subsidy: \n \n“New Entry Capacity Resource with State Subsidy” shall mean (1) starting with the 2022/2023 \nDelivery Year, the MWs (in installed capacity) comprising a Capacity Resource with State \nSubsidy that have not cleared in an RPM Auction pursuant to its Sell Offer at or above its \nresource-specific MOPR Floor Offer Price or the applicable default New Entry MOPR Floor \nOffer Price or (2) starting with the Base Residual Auction for the 2022/2023 Delivery Year, any \nof those MWs (in installed capacity) comprising a Capacity Resource with State Subsidy that \nwas not included in an FRR Capacity Plan at the time of the Base Residual Auction or the \nsubject of a Sell Offer in a Base Residual Auction occurring for a Delivery Year after it last \ncleared an RPM Auction and since then has yet to clear an RPM Auction pursuant to its Sell \nOffer at or above its resource-specific MOPR Floor Offer Price or the applicable default New \nEntry MOPR Floor Offer Price.  Notwithstanding the foregoing, any Capacity Resource that \npreviously cleared an RPM Auction before it became entitled to receive a State Subsidy shall not \nbe deemed a New Entry Capacity Resource, unless, starting with the Base Residual Auction for \nthe 2022/2023 Delivery Year, the Capacity Resource with State Subsidy was not the subject of a"},{"page":46,"startToken":15245,"endToken":15630,"text":"Sell Offer in a Base Residual Auction or included in an FRR Capacity Plan at the time of the \nBase Residual Auction for a Delivery Year after it last cleared an RPM Auction. \n \nNew Large Load: \n \n“New Large Load” shall mean end-use customer load that is either (a) a Large Load that goes \ninto service after June 1, 2027, or (b) incremental load in-service after June 1, 2027, that \nincreases the existing end-use customer load at a single electrical site that, prior to such \nincremental load, did not previously meet the definition of Large Load.  However, to the extent \nthree consecutive Delivery Years meet the requirements of Tariff, Attachment DD-4, section \nIV(b)(iii), then New Large Load shall mean end-use customer load that is either (a) a Large Load \nthat goes into service after June 1 of the first Delivery Year for which the requirements of Tariff, \nAttachment DD-4, section IV(b)(iii) are not met or (b) incremental load in-service after June 1 of \nthe first Delivery Year for which the requirements of Tariff, Attachment DD-4, section IV(b)(iii) \nare not met that increases the existing end-use customer load at a single electrical site that, prior \nto such incremental load, did not previously meet the definition of Large Load. \n \nNew PJM Zone(s): \n \n“New PJM Zone(s)” shall mean the Zone included in the Tariff, along with applicable Schedules \nand Attachments, for Commonwealth Edison Company, The Dayton Power and Light Company \nand the AEP East Operating Companies (Appalachian Power Company, Columbus Southern \nPower Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport \nPower Company, Ohio Power Company and Wheeling Power Company). \n \nNew Service Customers: \n \n“New Service Customers” shall mean all customers that submit an Interconnection Request, a \nCompleted Application, or an Upgrade Request that is pending in the New Services Queue. \n \nNew Service Request: \n \n“New Service Request” shall mean an Interconnection Request, a Completed Application, or an \nUpgrade Request. \n \nNew Services Queue: \n \n“New Services Queue” shall mean all Interconnection Requests, Completed Applications, and \nUpgrade Requests that are received within each six-month period ending on March 31 and \nSeptember 30 of each year shall collectively comprise a New Services Queue. \n \nNew York ISO or NYISO: \n \n“New York ISO” or “NYISO” shall mean the New York Independent System Operator, Inc. or \nany successor thereto."},{"page":47,"startToken":15630,"endToken":15983,"text":"Nodal Reference Price: \n  \nThe “Nodal Reference Price” at each location shall mean the 97th percentile price differential \nbetween day-ahead and real-time prices experienced over the corresponding two-month \nreference period in the prior calendar year.   Reference periods will be Jan-Feb, Mar-Apr, May-\nJun, Jul-Aug, Sept-Oct, Nov-Dec.  For any given current-year month, the reference period \nmonths will be the set of two months in the prior calendar year that include the month \ncorresponding to the current month.  For example, July and August 2003 would each use July-\nAugust 2002 as their reference period. \n \nNo-load Cost:  \n \n“No-load Cost” shall mean the hourly cost required to theoretically operate a synchronized unit \nat zero MW. It consists primarily of the cost of fuel, as determined by the unit’s no load heat \n(adjusted by the performance factor) times the fuel cost. It also includes operating costs, \nMaintenance Adders, and emissions allowances. \n \nNominal Rated Capability: \n \n“Nominal Rated Capability” shall mean the nominal maximum rated capability in megawatts of \na Transmission Interconnection Customer’s Customer Facility or the nominal increase in \ntransmission capability in megawatts of the Transmission System resulting from the \ninterconnection or addition of a Transmission Interconnection Customer’s Customer Facility, as \ndetermined in accordance with pertinent Applicable Standards and specified in the \nInterconnection Service Agreement. \n \nNominated Demand Resource Value: \n \n“Nominated Demand Resource Value” shall mean the amount of load reduction that a Demand \nResource commits to provide either through direct load control, firm service level or guaranteed \nload drop programs.  For existing Demand Resources, the maximum Nominated Demand \nResource Value is limited, in accordance with the PJM Manuals, to the value appropriate for the \nmethod by which the load reduction would be accomplished, at the time the Base Residual \nAuction or Incremental Auction is being conducted. \n \nNominated Energy Efficiency Value:  \n \n“Nominated Energy Efficiency Value” shall mean the amount of load reduction that an Energy \nEfficiency Resource commits to provide through installation of more efficient devices or \nequipment or implementation of more efficient processes or systems. \n \nNon-Curtailment Charge: \n \n“Non-Curtailment Charge” shall mean the charge applicable to Demand Resources and Price \nResponsive Demand as defined in Tariff, Attachment DD, section 10B(b)."},{"page":48,"startToken":15983,"endToken":16267,"text":"Non-Dispatched Charging Energy:  \n \n“Non-Dispatched Charging Energy” shall mean all Direct Charging Energy that an Energy \nStorage Resource Model Participant or Open-Loop Hybrid Resource receives from the electric \ngrid that is not otherwise Dispatched Charging Energy. \n \nNon-Firm Point-To-Point Transmission Service: \n \n“Non-Firm Point-To-Point Transmission Service” shall mean Point-To-Point Transmission \nService under the Tariff that is reserved and scheduled on an as-available basis and is subject to \nCurtailment or Interruption as set forth in Tariff, Part II, section 14.7.  Non-Firm Point-To-Point \nTransmission Service is available on a stand-alone basis for periods ranging from one hour to \none month. \n \nNon-Firm Sale: \n \n“Non-Firm Sale” shall mean an energy sale for which receipt or delivery may be interrupted for \nany reason or no reason, without liability on the part of either the buyer or seller. \n \nNon-Firm Transmission Withdrawal Rights: \n \n“No-Firm Transmission Withdrawal Rights” shall mean the rights to schedule energy \nwithdrawals from a specified point on the Transmission System. Non-Firm Transmission \nWithdrawal Rights may be awarded only to a Merchant D.C. Transmission Facility that connects \nthe Transmission System to another control area. Withdrawals scheduled using Non-Firm \nTransmission Withdrawal Rights have rights similar to those under Non-Firm Point-to-Point \nTransmission Service. \n \nNon-PAI Event: \n \n“Non-PAI Event” shall mean, effective for the 2028/2029 Delivery Year and subsequent \nDelivery Years, any intervals when a Demand Resource is dispatched or when Price Responsive \nDemand is required to respond and a Performance Assessment Interval is not in effect for such \nintervals for the same registration. \n \nNon-Performance Charge: \n \n“Non-Performance Charge” shall mean the charge applicable to Capacity Performance \nResources as defined in Tariff, Attachment DD, section 10A(e). \n \nNonincumbent Developer: \n \n“Nonincumbent Developer” shall have the same meaning provided in the Operating Agreement. \n \nNon-Regulatory Opportunity Cost:"},{"page":49,"startToken":16267,"endToken":16633,"text":"“Non-Regulatory Opportunity Cost” shall mean the difference between (a) the forecasted cost to \noperate a specific generating unit when the unit only has a limited number of starts or available \nrun hours resulting from (i) the physical equipment limitations of the unit, for up to one year, due \nto original equipment manufacturer recommendations or insurance carrier restrictions, (ii) a fuel \nsupply limitation, for up to one year, resulting from an event of Catastrophic Force Majeure; and,  \n(b) the forecasted future Locational Marginal Price at which the generating unit could run while \nnot violating such limitations.  Non-Regulatory Opportunity Cost therefore is the value \nassociated with a specific generating unit’s lost opportunity to produce energy during a higher \nvalued period of time occurring within the same period of time in which the unit is bound by the \nreferenced restrictions, and is reflected in the rules set forth in PJM Manual 15.  Non-Regulatory \nOpportunity Costs shall be limited to those resources which are specifically delineated in \nOperating Agreement, Schedule 2.  \n \nNon-Retail Behind The Meter Generation: \n \n“Non-Retail Behind The Meter Generation” shall mean Behind the Meter Generation that is used \nby municipal electric systems, electric cooperatives, or electric distribution companies to serve \nload. \n \nNon-Synchronized Reserve: \n \n“Non-Synchronized Reserve” shall mean the reserve capability of non-emergency generation \nresources that can be converted fully into energy within ten minutes of a request from the Office \nof the Interconnection dispatcher, and is provided by equipment that is not electrically \nsynchronized to the Transmission System. \n \nNon-Synchronized Reserve Event: \n \n“Non-Synchronized Reserve Event” shall mean a request from the Office of the Interconnection \nto generation resources able and assigned to provide Non-Synchronized Reserve in one or more \nspecified Reserve Zones or Reserve Sub-zones, within ten minutes to increase the energy output \nby the amount of assigned Non-Synchronized Reserve capability. \n \nNon-Variable Loads: \n“Non-Variable Loads” shall have the meaning specified in Operating Agreement, Schedule 1, \nsection 1.5A.6, and the parallel provisions of Tariff, Attachment K-Appendix, section 1.5A.6. \n \nNon-Zone Network Load: \n \n“Non-Zone Network Load shall mean Network Load that is located outside of the PJM Region. \n \nNormal Maximum Generation: \n \n“Normal Maximum Generation” shall mean the highest output level of a generating resource \nunder normal operating conditions."},{"page":50,"startToken":16633,"endToken":16653,"text":"Normal Minimum Generation: \n \n“Normal Minimum Generation” shall mean the lowest output level of a generating resource \nunder normal operating conditions."},{"page":51,"startToken":16653,"endToken":17022,"text":"Definitions – T – U - V \n \nTangible Net Worth: \n \n“Tangible Net Worth” shall mean total assets less goodwill and other intangible assets, minus \ntotal liabilities.   \n \nTarget Allocation: \n \n“Target Allocation” shall mean the allocation of Transmission Congestion Credits as set forth in \nOperating Agreement, Schedule 1, section 5.2.3, and the parallel provisions of Tariff, \nAttachment K-Appendix, section 5.2.3, or the allocation of Auction Revenue Rights Credits as \nset forth in Operating Agreement, Schedule 1, section 7.4.3, and the parallel provisions of Tariff, \nAttachment K-Appendix, section 7.4.3. \n \nThird Incremental Auction: \n \n“Third Incremental Auction” shall mean an Incremental Auction conducted three months before \nthe Delivery Year to which it relates. \n \nThird-Party Sale: \n \n“Third-Party Sale” shall mean any sale for resale in interstate commerce to a Power Purchaser \nthat is not designated as part of Network Load under the Network Integration Transmission \nService but not including a sale of energy through the PJM Interchange Energy Market \nestablished under the PJM Operating Agreement. \n \nTie Line: \n \n“Tie Line” shall mean a circuit connecting two balancing authority areas, Control Areas or fully \nmetered electric system regions. Tie Lines may be classified as external or internal as set forth in \nthe PJM Manuals. \n \nTotal Lost Opportunity Cost Offer:   \n \n“Total Lost Opportunity Cost Offer” shall mean the applicable offer used to calculate lost \nopportunity cost credits.  For pool-scheduled resources specified in PJM Operating Agreement, \nSchedule 1, section 3.2.3(f-1), and the parallel provisions of Tariff, Attachment K-Appendix, \nsection 3.2.3(f-1), the Total Lost Opportunity Cost Offer shall equal the Real-time Settlement \nInterval offer integrated under the applicable offer curve for the LOC Deviation, as determined by \nthe greater of the Committed Offer or last Real-Time Offer submitted for the offer on which the \nresource was committed in the Day-ahead Energy Market for each hour in an Operating Day.  For \nall other pool-scheduled resources, the Total Lost Opportunity Cost Offer shall equal the Real-\ntime Settlement Interval offer integrated under the applicable offer curve for the LOC Deviation, \nas determined by the offer curve associated with the greater of the Committed Offer or Final Offer \nfor each hour in an Operating Day.   For self-scheduled generation resources, the Total Lost"},{"page":52,"startToken":17022,"endToken":17457,"text":"Opportunity Cost Offer shall equal the Real-time Settlement Interval offer integrated under the \napplicable offer curve for the LOC Deviation, where for self-scheduled generation resources (a) \noperating pursuant to a cost-based offer, the applicable offer curve shall be the greater of the \noriginally submitted cost-based offer or the cost-based offer that the resource was dispatched on \nin real-time; or (b) operating pursuant to a market-based offer, the applicable offer curve shall be \ndetermined in accordance with the following process: (1) select the greater of the cost-based day-\nahead offer and updated cost-based Real-time Offer; (2) for resources with multiple cost-based \noffers, first, for each cost-based offer select the greater of the day-ahead offer and updated Real-\ntime Offer, and then select the lesser of the resulting cost-based offers; and (3) compare the offer \nselected in (1), or for resources with multiple cost-based offers the offer selected in (2), with the \nmarket-based day-ahead offer and the market-based Real-time Offer and select the highest offer. \n \nTotal Net Obligation: \n  \n“Total Net Obligation” shall mean all unpaid billed Net Obligations plus any unbilled Net \nObligation incurred to date, as determined by PJMSettlement on a daily basis, plus any other \nObligations owed to PJMSettlement at the time. \n \nTotal Net Sell Position: \n \n“Total Net Sell Position” shall mean all unpaid billed Net Sell Positions plus any unbilled Net \nSell Positions accrued to date, as determined by PJMSettlement on a daily basis. \n \nTotal Operating Reserve Offer:   \n \n“Total Operating Reserve Offer” shall mean the applicable offer used to calculate Operating \nReserve credits.  The Total Operating Reserve Offer shall equal the sum of all individual Real-\ntime Settlement Interval energy offers, inclusive of Start-Up Costs (shut-down costs for Demand \nResources) and No-load Costs, for every Real-time Settlement Interval in a Segment, integrated \nunder the applicable offer curve up to the applicable megawatt output as further described in the \nPJM Manuals.  The applicable offer used to calculate day-ahead Operating Reserve credits shall \nbe the Committed Offer, and the applicable offer used to calculate balancing Operating Reserve \ncredits shall be lesser of the Committed Offer or Final Offer for each hour in an Operating Day. \n \nTrade Reference:  \n \n“Trade Reference” shall mean a reference from a contact or firm that had or has a material \nbusiness relationship with a Participant. \n \nTransmission Congestion Charge: \n \n“Transmission Congestion Charge” shall mean a charge attributable to the increased cost of \nenergy delivered at a given load bus when the transmission system serving that load bus is \noperating under constrained conditions, or as necessary to provide energy for third-party \ntransmission losses which shall be calculated and allocated as specified in Operating Agreement,"},{"page":53,"startToken":17457,"endToken":17783,"text":"Schedule 1, section 5.1 and the parallel provisions of Tariff, Attachment K-Appendix, section \n5.1. \n \nTransmission Congestion Credit: \n \n“Transmission Congestion Credit” shall mean the allocated share of total Transmission \nCongestion Charges credited to each FTR Holder, calculated and allocated as specified in \nOperating Agreement, Schedule 1, section 5.2, and the parallel provisions of Tariff, Attachment \nK-Appendix, section 5.2. \n \nTransmission Constraint Penalty Factor: \n \n“Transmission Constraint Penalty Factor” shall mean the maximum cost of the re-dispatch \nincurred to control the flows across a transmission constraint and establishes the maximum limit \non the Marginal Value. \n \nTransmission Customer: \n \n“Transmission Customer” shall mean any Eligible Customer (or its Designated Agent) that (i) \nexecutes a Service Agreement, or (ii) requests in writing that the Transmission Provider file with \nthe Commission a proposed unexecuted Service Agreement, to receive transmission service \nunder Tariff, Part II.  This term is used in Tariff, Part I and Tariff, Part VI to include customers \nreceiving transmission service under Tariff, Part II and Tariff, Part III. \n \nWhere used in Tariff, Attachment K-Appendix and the parallel provisions of Operating \nAgreement, Schedule 1, Transmission Customer shall mean an entity using Point-to-Point \nTransmission Service. \n \nTransmission Facilities: \n \n“Transmission Facilities” shall have the meaning set forth in the Operating Agreement. \n \nTransmission Forced Outage: \n \n“Transmission Forced Outage” shall mean an immediate removal from service of a transmission \nfacility by reason of an Emergency or threatened Emergency, unanticipated failure, or other \ncause beyond the control of the owner or operator of the transmission facility, as specified in the \nrelevant portions of the PJM Manuals.  A removal from service of a transmission facility at the \nrequest of the Office of the Interconnection to improve transmission capability shall not \nconstitute a Forced Transmission Outage. \n \nTransmission Facility Rating: \n \n“Transmission Facility Rating” shall mean the maximum transfer capability, or the maximum or \nminimum voltage, current, frequency, or real or reactive power flow, through a Transmission \nFacility that does not violate the applicable rating of relevant transmission equipment."},{"page":54,"startToken":17783,"endToken":18083,"text":"Transmission Facility Ratings are computed in accordance with a written Transmission Facility \nRating methodology and consistent with Good Utility Practice, considering the technical \nlimitations on conductors and relevant transmission equipment (such as thermal flow limits).  \nRelevant transmission equipment may include, but is not limited to, circuit breakers, line traps, \nand transformers.  Transmission Facility Ratings also encompass AARs, AAR Exceptions, and \nTemporary Conditional Transmission Facility Ratings. \n \nTransmission Injection Rights: \n \n“Transmission Injection Rights” shall mean Capacity Transmission Injection Rights and Energy \nTransmission Injection Rights. \n \nTransmission Interconnection Customer: \n \n“Transmission Interconnection Customer” shall mean an entity that submits an Interconnection \nRequest to interconnect or add Merchant Transmission Facilities to the Transmission System or \nto increase the capacity of Merchant Transmission Facilities interconnected with the \nTransmission System in the PJM Region or an entity that submits an Upgrade Request for \nMerchant Network Upgrades (including accelerating the construction of any transmission \nenhancement or expansion, other than Merchant Transmission Facilities, that is included in the \nRegional Transmission Expansion Plan prepared pursuant to Operating Agreement, Schedule 6). \n \nTransmission Interconnection Facilities Study: \n \n“Transmission Interconnection Facilities Study” shall mean a Facilities Study related to a \nTransmission Interconnection Request. \n \nTransmission Interconnection Feasibility Study: \n \n“Transmission Interconnection Feasibility Study” shall mean a study conducted by the \nTransmission Provider in accordance with Tariff, Part IV, section 36.2. \n \nTransmission Interconnection Request: \n \n“Transmission Interconnection Request” shall mean a request by a Transmission Interconnection \nCustomer pursuant to Tariff, Part IV to interconnect or add Merchant Transmission Facilities to \nthe Transmission System or to increase the capacity of existing Merchant Transmission Facilities \ninterconnected with the Transmission System in the PJM Region. \n \nTransmission Loading Relief: \n \n“Transmission Loading Relief” shall mean NERC’s procedures for preventing operating security \nlimit violations, as implemented by PJM as the security coordinator responsible for maintaining \ntransmission security for the PJM Region. \n \nTransmission Loss Charge:"},{"page":55,"startToken":18083,"endToken":18395,"text":"“Transmission Loss Charge” shall mean the charges to each Market Participant, Network \nCustomer, or Transmission Customer for the cost of energy lost in the transmission of electricity \nfrom a generation resource to load as specified in Operating Agreement, Schedule 1, section 5, \nand the parallel provisions of Tariff, Attachment K-Appendix, section 5. \n \nTransmission Owner: \n \n“Transmission Owner” shall mean a Member that owns or leases with rights equivalent to \nownership Transmission Facilities and is a signatory to the PJM Transmission Owners \nAgreement.  Taking transmission service shall not be sufficient to qualify a Member as a \nTransmission Owner. \n \nTransmission Owner Attachment Facilities: \n \n“Transmission Owner Attachment Facilities” shall mean that portion of the Transmission Owner \nInterconnection Facilities comprised of all Attachment Facilities on the Interconnected \nTransmission Owner’s side of the Point of Interconnection.  \n \nTransmission Owner Interconnection Facilities: \n \n“Transmission Owner Interconnection Facilities” shall mean all Interconnection Facilities that \nare not Customer Interconnection Facilities and that, after the transfer under Tariff, Attachment \nP, Appendix 2, section 5.5 to the Interconnected Transmission Owner of title to any \nTransmission Owner Interconnection Facilities that the Interconnection Customer constructed, \nare owned, controlled, operated and maintained by the Interconnected Transmission Owner on \nthe Interconnected Transmission Owner’s side of the Point of Interconnection identified in \nappendices to the Interconnection Service Agreement and to the Interconnection Construction \nService Agreement, including any modifications, additions or upgrades made to such facilities \nand equipment, that are necessary to physically and electrically interconnect the Customer \nFacility with the Transmission System or interconnected distribution facilities. \n \nTransmission Owner Upgrade:  \n \n“Transmission Owner Upgrade” shall have the same meaning provided in the Operating \nAgreement. \n \nTransmission Planned Outage: \n \n“Transmission Planned Outage” shall mean any transmission outage scheduled in advance for a \npre-determined duration and which meets the notification requirements for such outages \nspecified in Operating Agreement, Schedule 1, and the parallel provisions of Tariff, Attachment \nK-Appendix or the PJM Manuals. \n \nTransmission Provider:"},{"page":56,"startToken":18395,"endToken":18677,"text":"The “Transmission Provider” shall be the Office of the Interconnection for all purposes, provided \nthat the Transmission Owners will have the responsibility for the following specified activities: \n \n(a) \nThe Office of the Interconnection shall direct the operation and coordinate the \nmaintenance of the Transmission System, except that the Transmission Owners will continue to \ndirect the operation and maintenance of those transmission facilities that are not listed in the PJM \nDesignated Facilities List contained in the PJM Manual on Transmission Operations; \n \n(b) \nEach Transmission Owner shall physically operate and maintain all of the facilities that it \nowns; and \n \n(c) \nWhen studies conducted by the Office of the Interconnection indicate that enhancements \nor modifications to the Transmission System are necessary, the Transmission Owners shall have \nthe responsibility, in accordance with the applicable terms of the Tariff, Operating Agreement \nand/or the Consolidated Transmission Owners Agreement to construct, own, and finance the \nneeded facilities or enhancements or modifications to facilities. \n \nTransmission Provider’s Monthly Transmission System Peak: \n \n“Transmission Provider’s Monthly Transmission System Peak” shall mean the maximum firm \nusage of the Transmission Provider’s Transmission System in a calendar month. \n \nTransmission Service: \n \n“Transmission Service” shall mean Point-To-Point Transmission Service provided under Tariff, \nPart II on a firm and non-firm basis. \n \nTransmission Service Request: \n \n“Transmission Service Request” shall mean a request for Firm Point-To-Point Transmission \nService or a request for Network Integration Transmission Service. \n \nTransmission System: \n \n“Transmission System” shall mean the facilities controlled or operated by the Transmission \nProvider within the PJM Region that are used to provide transmission service under Tariff, Part \nII and Part III. \n \nTransmission Withdrawal Rights: \n \n“Transmission Withdrawal Rights” shall mean Firm Transmission Withdrawal Rights and Non-\nFirm Transmission Withdrawal Rights. \n \nTurn Down Ratio:"},{"page":57,"startToken":18677,"endToken":19049,"text":"“Turn Down Ratio” shall mean the ratio of a generating unit’s economic maximum megawatts to \nits economic minimum megawatts. \n \nUnconstrained LDA Group: \n \n“Unconstrained LDA Group” shall mean a combined group of LDAs that form an electrically \ncontiguous area and for which a separate Variable Resource Requirement Curve has not been \nestablished under Tariff, Attachment DD, section 5.10.  Any LDA for which a separate Variable \nResource Requirement Curve has not been established under Tariff, Attachment DD, section \n5.10 shall be combined with all other such LDAs that form an electrically contiguous area. \n \nUnforced Capacity: \n \n“Unforced Capacity” shall have the meaning specified in the Reliability Assurance Agreement. \n \nUnsecured Credit: \n  \n“Unsecured Credit” shall mean any credit granted by PJMSettlement to a Participant that is not \nsecured by Collateral. \n \nUnsecured Credit Allowance: \n  \n“Unsecured Credit Allowance” shall mean Unsecured Credit extended by PJMSettlement in an \namount determined by PJMSettlement’s evaluation of the creditworthiness of a Participant.  This \nis also defined as the amount of credit that a Participant qualifies for based on the strength of its \nown financial condition without having to provide Collateral.  See also: “Working Credit Limit.” \n \nUpdated VRR Curve: \n \n“Updated VRR Curve” shall mean the Variable Resource Requirement Curve for use in the Base \nResidual Auction of the relevant Delivery Year, updated to reflect any changes in the Reliability \nRequirement, Excluded RTO New Large Load Amounts, and/or Excluded LDA New Large \nLoad Amounts from the Base Residual Auction to the relevant Incremental Auction. \n \nUpdated VRR Curve Decrement: \n \n“Updated VRR Curve Decrement” shall mean the portion of the Updated VRR Curve to the left \nof a vertical line at the level of Unforced Capacity on the x-axis of such curve equal to the net \nUnforced Capacity committed to the PJM Region as a result of all prior auctions conducted for \nsuch Delivery Year and adjusted, if applicable, by a change in Unforced Capacity commitments \nassociated with Tariff, Attachment DD, section 5.5A(c)(i)(B), and RAA, Schedule 6, section L.9.   \n \nUpdated VRR Curve Increment: \n \n“Updated VRR Curve Increment” shall mean the portion of the Updated VRR Curve to the right \nof a vertical line at the level of Unforced Capacity on the x-axis of such curve equal to the net"},{"page":58,"startToken":19049,"endToken":19372,"text":"Unforced Capacity committed to the PJM Region as a result of all prior auctions conducted for \nsuch Delivery Year and adjusted, if applicable, by a change in Unforced Capacity commitments \nassociated with Tariff, Attachment DD, section 5.5A(c)(i)(B), and RAA, Schedule 6, section L.9. \n \nUpgrade Construction Service Agreement: \n \n“Upgrade Construction Service Agreement” shall mean that agreement entered into by an \nEligible Customer, Upgrade Customer or Interconnection Customer proposing Merchant \nNetwork Upgrades, a Transmission Owner, and the Transmission Provider, pursuant to Tariff, \nPart VI, Subpart B, and in the form set forth in Tariff, Attachment GG. \n \nUpgrade Customer: \n \n“Upgrade Customer” shall mean a customer that submits an Upgrade Request pursuant to \nOperating Agreement, Schedule 1, section 7.8, and the parallel provisions of Tariff, Attachment \nK-Appendix, section 7.8. \n \nUpgrade Feasibility Study: \n \n“Upgrade Feasibility Study” shall mean a study conducted by the Transmission Provider in \naccordance with Tariff, Part IV, section 36.3. \n \nUpgrade-Related Rights: \n \n“Upgrade-Related Rights” shall mean Incremental Auction Revenue Rights, Incremental \nAvailable Transfer Capability Revenue Rights, Incremental Deliverability Rights, and \nIncremental Capacity Transfer Rights. \n \nUpgrade Request: \n \n“Upgrade Request” shall mean a request submitted in the form prescribed in Tariff, Attachment \nEE, for evaluation by the Transmission Provider of the feasibility and estimated costs of (a) a \nMerchant Network Upgrade or (b) the Customer-Funded Upgrades that would be needed to \nprovide Incremental Auction Revenue Rights specified in a request pursuant to Operating \nAgreement, Schedule 1, section 7.8, and the parallel provisions of Tariff, Attachment K-\nAppendix, section 7.8. \n \nUp-to Congestion Counterflow Transaction: \n \n“Up-to Congestion Counterflow Transaction” shall mean an Up-to Congestion Transaction will \nbe deemed an Up-to Congestion Counterflow Transaction if the following value is negative:  (a) \nwhen bidding, the lower of the bid price and the prior Up-to Congestion Historical Month’s \naverage real-time value for the transaction; or (b) for cleared Virtual Transactions, the cleared \nday-ahead price of the Virtual Transactions. \n \nUp-to Congestion Historical Month:"},{"page":59,"startToken":19372,"endToken":19686,"text":"“Up-to Congestion Historical Month” shall mean a consistently-defined historical period \nnominally one month long that is as close to a calendar month as PJM determines is practical. \n \nUp-to Congestion Prevailing Flow Transaction: \n \nAn Up-to Congestion Transaction shall mean an “Up-to Congestion Prevailing Flow \nTransaction” if it is not an Up-to Congestion Counterflow Transaction. \n \nUp-to Congestion Reference Price: \n \n“Up-to Congestion Reference Price” for an Up-to Congestion Transaction, shall be the specified \npercentile price differential between source and sink (defined as sink price minus source price) \nfor real-time prices experienced over the prior Up-to Congestion Historical Month, averaged \nwith the same percentile value calculated for the second prior Up-to Congestion Historical \nMonth.  Up-to Congestion Reference Prices shall be calculated using the following historical \npercentiles: \n \nFor Up-to Congestion Prevailing Flow Transactions: 30th percentile \n \nFor Up-to Congestion Counterflow Transactions when bid:  20th percentile \n \nFor Up-to Congestion Counterflow Transactions when cleared:  5th percentile \n \nUp-to Congestion Transaction: \n \n“Up-to Congestion Transaction” shall have the meaning specified in Operating Agreement, \nSchedule 1, section 1.10.1A, and the parallel provisions of Tariff, Attachment K-Appendix, \nsection 1.10.1A. \n \nVariable Loads: \n“Variable Loads” shall have the meaning specified in Operating Agreement, Schedule 1, section \n1.5A.6, and the parallel provisions of Tariff, Attachment K-Appendix, section 1.5A.6. \n \nVariable Resource Requirement Curve:  \n \n“Variable Resource Requirement Curve” shall mean a series of maximum prices that can be \ncleared in a Base Residual Auction for Unforced Capacity, corresponding to a series of varying \nresource requirements based on varying installed reserve margins, as determined by the Office of \nthe Interconnection for the PJM Region and for certain Locational Deliverability Areas in \naccordance with the methodology provided in Tariff, Attachment DD, section 5. \n \nVirtual Credit Exposure:  \n“Virtual Credit Exposure” shall mean the amount of potential credit exposure created by a \nmarket participant’s bid submitted into the Day-ahead market, as defined in Tariff, Attachment \nQ. \n \nVirtual Transaction:"},{"page":60,"startToken":19686,"endToken":19919,"text":"“Virtual Transaction” shall mean a Decrement Bid, Increment Offer and/or Up-to Congestion \nTransaction. \n \nVirtual Transaction Screening: \n  \n“Virtual Transaction Screening” shall be the process of reviewing the Virtual Credit Exposure of \nsubmitted Virtual Transactions against the Credit Available for Virtual Transactions.  If the \ncredit required is greater than credit available, then the Virtual Transactions will not be accepted. \n \nVirtual Transactions Net Activity: \n \n“Virtual Transactions Net Activity” shall mean the aggregate net total, resulting from Virtual \nTransactions, of (i) Spot Market Energy charges, (ii) Transmission Congestion Charges, and (iii) \nTransmission Loss Charges, calculated as set forth in Tariff, Attachment K-Appendix, and the \nparallel provisions of Operating Agreement, Schedule 1.  Virtual Transactions Net Activity may \nbe positive or negative. \n \nVoltage Reduction Action: \n \n“Voltage Reduction Action” shall mean a notification during capacity deficient conditions in \nwhich PJM notifies Members to reduce voltage on the distribution system in order to reduce \ndemand and therefore provide a sufficient amount of reserves, maintain tie flow schedules and \npreserve limited energy sources. \n \nVoltage Reduction Alert: \n \n“Voltage Reduction Alert” shall mean a notification from PJM to alert Members that a voltage \nreduction may be required during a future critical period. \n \nVoltage Reduction Warning: \n \n“Voltage Reduction Warning” shall mean a notification from PJM to warn Members that PJM’s \navailable Synchronized Reserve is less than the Synchronized Reserve Requirement and that \npresent operations have deteriorated such that a voltage reduction may be required."},{"page":61,"startToken":19919,"endToken":20390,"text":"5.4 \nReliability Pricing Model Auctions \n \nThe Office of the Interconnection shall conduct the following Reliability Pricing Model \nAuctions: \n \n \na) \nBase Residual Auction. \n \nPJM shall conduct for each Delivery Year a Base Residual Auction to secure commitments of \nCapacity Resources as needed to satisfy the portion of the RTO Unforced Capacity Obligation \nnot satisfied through Self-Supply of Capacity Resources for such Delivery Year.  All Self-Supply \nCapacity Resources must be offered in the Base Residual Auction.  As set forth in Tariff, \nAttachment DD, section 6.6, all other Capacity Resources, and certain other existing generation \nresources, must be offered in the Base Residual Auction.  The Base Residual Auction shall be \nconducted in the month of May that is three years prior to the start of such Delivery Year.  \nNotwithstanding, the Base Residual Auction for the 2026/2027 Delivery Year shall be conducted \nin July 2025; the Base Residual Auction for the 2027/2028 Delivery Year shall be conducted in \nDecember 2025; the Base Residual Auction for the 2028/2029 Delivery Year shall be conducted \nin June 2026; and the Base Residual Auction for the 2029/2030 Delivery Year shall be \nconducted in December 2026.  The cost of payments to Capacity Market Sellers for Capacity \nResources that clear such auction shall be paid by PJMSettlement from amounts collected by \nPJMSettlement from Load Serving Entities through the Locational Reliability Charge during \nsuch Delivery Year. PJMSettlement shall be the Counterparty to the sales that clear in such \nauction and to the obligations to pay, and the payments, by Load Serving Entities; provided, \nhowever, that PJMSettlement shall not be a Counterparty to committed Self-Supply Capacity \nResources.  \n \n \nb) \nScheduled Incremental Auctions. \n \nPJM shall conduct for each Delivery Year a First, a Second, and a Third Incremental Auction.  \nThe First Incremental Auction shall be conducted in the month of September that is twenty \nmonths prior to the start of the Delivery Year; the Second Incremental Auction shall be \nconducted in the month of July that is ten months prior to the start of the Delivery Year; and the \nThird Incremental Auction shall be conducted in the month of February that is three months prior \nto the start of the Delivery Year.  Notwithstanding, for the 2025/2026 Delivery Year, only the \nThird Incremental Auction shall be conducted, which will commence on February 2025; for the \n2026/2027 Delivery Year, only the Third Incremental Auction shall be conducted, which will \ncommence on February 2026; for the 2027/2028 Delivery Year, only the Second Incremental \nAuction and Third Incremental Auction shall be conducted, which will commence on July 2026 \nand February 2027, respectively; for the 2028/2029 Delivery Year, only the Second Incremental \nAuction and Third Incremental Auction shall be conducted, which shall commence on July 2027 \nand February 2028, respectively. \n \n \nc) \nAdjustment through Scheduled Incremental Auctions of Capacity Previously \nCommitted."},{"page":62,"startToken":20390,"endToken":20914,"text":"The Office of the Interconnection shall recalculate the PJM Region Reliability Requirement and \neach LDA Reliability Requirement (inclusive of any updated adjustments to the Excluded RTO \nNew Large Load Amounts and/or Excluded LDA New Large Load Amounts) prior to each \nScheduled Incremental Auction, based on an updated peak load forecast, updated Installed \nReserve Margin and an updated Capacity Emergency Transfer Objective; shall update such \nreliability requirements (and inclusive of any updated adjustments to the Excluded RTO New \nLarge Load Amounts and/or Excluded LDA New Large Load Amounts) for the Third \nIncremental Auction to reflect any change from such recalculation; and shall update such \nreliability requirements (and inclusive of any updated adjustments to the Excluded RTO New \nLarge Load Amounts and/or Excluded LDA New Large Load Amounts) for the First Incremental \nAuction or Second Incremental Auction only if the change is greater than or equal to the lesser \nof: (i) 500 MW or (ii) one percent of the applicable prior reliability requirement.  Based on such \nupdate, the Office of the Interconnection shall, under certain conditions, seek through the \nScheduled Incremental Auction to secure additional commitments of capacity or release sellers \nfrom prior capacity commitments.  Specifically, the Office of the Interconnection shall: \n \n1) \nseek additional capacity commitments to serve the PJM Region or an LDA \nif the PJM Region Reliability Requirement or LDA Reliability Requirement utilized in the most \nrecent prior auction conducted for the Delivery Year (including any reductions to such reliability \nrequirements as a result of any Price Responsive Demand with a PRD Reservation Price equal to \nor lower than the clearing price in the Base Residual Auction for such Delivery Year and any \nadjustments associated with Excluded RTO New Large Load Amounts or Excluded LDA New \nLarge Load Amounts) is less than, respectively, the updated PJM Region Reliability \nRequirement or updated LDA Reliability Requirement (inclusive of any updated adjustments to \nthe Excluded RTO New Large Load Amounts and/or Excluded LDA New Large Load \nAmounts); provided, however, that in the First Incremental Auction or Second Incremental \nAuction the Office of the Interconnection shall seek such additional capacity commitments only \nif such shortfall is in an amount greater than or equal to the lesser of: (i) 500 MW or (ii) one \npercent of the applicable prior reliability requirement; \n \n2) \nseek additional capacity commitments to serve the PJM Region or an LDA \nif: \n \ni)  \nthe updated PJM Region Reliability Requirement or the LDA Reliability \nRequirement (inclusive of any adjustments associated with Excluded RTO New \nLarge Load Amounts or Excluded LDA New Large Load Amounts) applicable to \nsuch auction, exceeds the total capacity committed in all prior auctions in such \nregion or area, respectively, for such Delivery Year by an amount greater than or \nequal to the lesser of: (A) 500 MW or (B) one percent of the applicable prior \nreliability requirement;  \n \nii)   \nPJM conducts a Conditional Incremental Auction for such Delivery Year \nand does not obtain all additional commitments of Capacity Resources sought in \nsuch Conditional Incremental Auction, in which case, PJM shall seek in the \nIncremental Auction the commitments that were sought in the Conditional \nIncremental Auction but not obtained; or"},{"page":63,"startToken":20914,"endToken":21388,"text":"iii)  \nregarding a Generation Capacity Resource that is subject to Tariff, \nAttachment DD, section 5.3(b), (a) the Office of Interconnection determines prior \nto the Third Incremental Auction that such resource will not meet the criteria set \nforth in Tariff, Attachment DD, section 5.3(b)(i) for the relevant Delivery Year or \n(b) such resource’s final Accredited UCAP is less than the UCAP amount \nconsidered in the Base Residual Auction in which the resource was deemed to be \nthe subject of a Sell Offer. \n \n3) \nseek agreements to release prior capacity commitments to the PJM Region \nor to an LDA if: \n \ni)  \nthe PJM Region Reliability Requirement or LDA Reliability Requirement \nutilized in the most recent prior auction conducted for the Delivery Year \n(including any reductions to such reliability requirements as a result of any Price \nResponsive Demand with a PRD Reservation Price equal to or lower than the \nclearing price in the Base Residual Auction for such Delivery Year and any \nadjustments associated with Excluded RTO New Large Load Amounts or \nExcluded LDA New Large Load Amounts) exceeds, respectively, the updated \nPJM Region Reliability Requirement or updated LDA Reliability Requirement \n(inclusive of any updated adjustments to the Excluded RTO New Large Load \nAmounts and/or Excluded LDA New Large Load Amounts); provided, however, \nthat in the First Incremental Auction or Second Incremental Auction the Office of \nthe Interconnection shall seek such agreements only if such excess is in an \namount greater than or equal to the lesser of: (A) 500 MW or (B) one percent of \nthe applicable prior reliability requirement; or \n \nii)   \nPJM obtains additional commitments of Capacity Resources in a \nConditional Incremental Auction, in which case PJM shall seek release of an \nequal number of megawatts (comparing the total purchase amount for all LDAs \nand the PJM Region related to the delay in Backbone Transmission with the total \nsell amount for all LDAs and the PJM Region related to the delay in Backbone \nTransmission) of prior committed capacity that would not have been committed \nhad the delayed Backbone Transmission upgrade that prompted the Conditional \nIncremental Auction not been assumed, at the time of the Base Residual Auction, \nto be in service for the relevant Delivery Year; and if PJM obtains additional \ncommitments of capacity in an incremental auction pursuant to subsection c.2.ii \nabove, PJM shall seek in such Incremental Auction to release an equal amount of \ncapacity (in total for all LDAs and the PJM Region related to the delay in \nBackbone Transmission) previously committed that would not have been \ncommitted absent the Backbone Transmission upgrade.  \n \n4) \nThe cost of payments to Market Sellers for additional Capacity Resources \ncleared in such auctions, and the credits from payments from Market Sellers for the release of \npreviously committed Capacity Resources, shall be apportioned to Load Serving Entities in the"},{"page":64,"startToken":21388,"endToken":21872,"text":"PJM Region or LDA, as applicable, through adjustments to the Locational Reliability Charge \nfor such Delivery Year. \n \n5) \nPJMSettlement shall be the Counterparty to the sales (including releases) \nof Capacity Resources that clear in such auctions and to the obligations to pay, and the payments, \nby Load Serving Entities, provided, however, that PJMSettlement shall not be a Counterparty to \ncommitted Self-Supply Capacity Resources.   \n \n \nd) \nCommitment of Replacement Capacity through Scheduled Incremental Auctions. \n \nEach Scheduled Incremental Auction for each Delivery Year shall allow Capacity \nMarket Sellers that committed Capacity Resources in any prior Reliability Pricing Model \nAuction for such Delivery Year to submit Buy Bids for replacement Capacity Resources.  \nCapacity Market Sellers that submit Buy Bids into an Incremental Auction must specify the type \nof Unforced Capacity desired, i.e., Annual Resource.  The need to purchase replacement \nCapacity Resources may arise for any reason, including but not limited to resource retirement, \nresource cancellation or construction delay, resource derating, EFORd increase, decrease in \nAccredited UCAP Factor, a decrease in the Nominated Demand Resource Value of a Planned \nDemand Resource, delay or cancellation of a Qualifying Transmission Upgrade, or similar \noccurrences.  The cost of payments to Capacity Market Sellers for Capacity Resources that clear \nsuch auction shall be paid by PJMSettlement from amounts collected by PJMSettlement from \nCapacity Market Buyers that purchase replacement Capacity Resources in such auction.  \nPJMSettlement shall be the Counterparty to the sales and purchases that clear in such auction, \nprovided, however, PJMSettlement shall not be a Counterparty to committed Self-Supply \nCapacity Resources. \n \n \n \ne) \nConditional Incremental Auction. \n \nPJM shall conduct for any Delivery Year a Conditional Incremental Auction if the in service date \nof a Backbone Transmission Upgrade that was modeled in the Base Residual Auction is \nannounced as delayed by the Office of the Interconnection beyond July 1 of the Delivery Year \nfor which it was modeled and if such delay causes a reliability criteria violation.  If conducted, \nthe Conditional Incremental Auction shall be for the purpose of securing commitments of \nadditional capacity for the PJM Region or for any LDA to address the identified reliability \ncriteria violation.  If PJM determines to conduct a Conditional Incremental Auction, PJM shall \npost on its website the date and parameters for such auction (including whether such auction is \nfor the PJM Region or for an LDA, and the type of Capacity Resources required) at least one \nmonth prior to the start of such auction.  The cost of payments to Market Sellers for Capacity \nResources cleared in such auction shall be collected by PJMSettlement from Load Serving \nEntities in the PJM Region or LDA, as applicable, through an adjustment to the Locational \nReliability Charge for such Delivery Year.  PJMSettlement shall be the Counterparty to the sales \nthat clear in such auction and to the obligations to pay, and payments, by Load Serving Entities, \nprovided, however, that PJMSettlement shall not be a Counterparty to committed Self-Supply \nCapacity Resources."},{"page":65,"startToken":21872,"endToken":22283,"text":"5.10 \nAuction Clearing Requirements \n \nThe Office of the Interconnection shall clear each Base Residual Auction and Incremental \nAuction for a Delivery Year in accordance with the following: \n \n \na) \nVariable Resource Requirement Curve  \n \nThe Office of the Interconnection shall determine Variable Resource Requirement Curves for the \nPJM Region and for such Locational Deliverability Areas as determined appropriate in \naccordance with subsection (a)(iii) for such Delivery Year to establish the level of Capacity \nResources that will provide an acceptable level of reliability consistent with the Reliability \nPrinciples and Standards. It is recognized that the variable resource requirement reflected in the \nVariable Resource Requirement Curve can result in an optimized auction clearing in which the \nlevel of Capacity Resources committed for a Delivery Year exceeds the PJM Region Reliability \nRequirement or Locational Deliverability Area Reliability Requirement for such Delivery Year. \nFor any auction, the Updated Forecast Peak Load applicable to such auction, shall be used, and \nPrice Responsive Demand from any applicable approved PRD Plan, including any associated \nPRD Reservation Prices, shall be reflected in the derivation of the Variable Resource \nRequirement Curves, in accordance with the methodology specified in the PJM Manuals. \n \ni) \nMethodology to Establish the Variable Resource Requirement Curve  \n \nPrior to the Base Residual Auction, in accordance with the schedule in the PJM Manuals, the \nOffice of the Interconnection shall establish the Variable Resource Requirement Curve for the \nPJM Region as follows: \n \n \nEach Variable Resource Requirement Curve shall be plotted on a graph on \nwhich Unforced Capacity is on the x-axis and price is on the y-axis. \n \n \nFor the 2025/2026 Delivery Year, the Variable Resource Requirement \ncurve for the PJM Region shall be plotted by combining (i) a horizontal line \nfrom the y-axis to point (1), (ii) a straight line connecting points (1) and (2), \nand (iii) a straight line connecting points (2) and (3), where: \n \n \n For point (1), price equals: {the greater of [the Cost of New Entry] \nor [1.5 times (the Cost of New Entry minus the Net Energy and \nAncillary Service Revenue Offset)]} divided by (the applicable \nELCC Class Rating of the Reference Resource) and Unforced \nCapacity equals: [the PJM Region Reliability Requirement \nmultiplied by 98.9%]; \n \n \n For point (2), price equals: [0.75 times (the Cost of New Entry \nminus the Net Energy and Ancillary Service Revenue Offset)] \ndivided by (the applicable ELCC Class Rating of the Reference \nResource) and Unforced Capacity equals: [the PJM Region \nReliability Requirement multiplied by 101.6%]; and"},{"page":66,"startToken":22283,"endToken":22699,"text":" \n For point (3), price equals zero and Unforced Capacity equals: [the \nPJM Region Reliability Requirement multiplied by 106.8%]. \n \n \nFor the 2026/2027 Delivery Year and 2027/2028 Delivery Years, the \nVariable Resource Requirement Curve for the PJM Region shall be plotted \nby a horizontal line from the y-axis equal to $256.75/MW-day ICAP \ndivided by the applicable ELCC Class Rating for the Reference Resource \nuntil such line intersects the curve that is based on the following: (i) a \nstraight line connecting points (1) and (2), and (ii) a straight line connecting \npoints (2) and (3), where: \n \n \nFor point (1), price equals: {the greater of [the Cost of New Entry] \nor [1.75 times (the Cost of New Entry minus the Net Energy and \nAncillary Service Revenue Offset)]} divided by (the applicable \nELCC Class Rating of the Reference Resource) and Unforced \nCapacity equals: [the PJM Region Reliability Requirement \nmultiplied by 99%]; \n \n \nFor point (2), price equals: [0.75 times (the Cost of New Entry minus \nthe Net Energy and Ancillary Service Revenue Offset)] divided by \n(the applicable ELCC Class Rating of the Reference Resource) and \nUnforced \nCapacity \nequals: \n[the \nPJM \nRegion \nReliability \nRequirement multiplied by 101.5%]; and \n \n \nFor point (3), price equals zero and Unforced Capacity equals: [the \nPJM Region Reliability Requirement multiplied by 104.5%]. \n \n \nOnce the horizontal line intersects the above curve, the Variable Resource \nRequirement Curve shall follow the lines that are based on the above points \nuntil the price reaches $138.25/MW-day ICAP divided by the applicable \nELCC Class Rating of the Reference Resource, at which point it shall be \nextended as a horizontal line at $138.25/MW-day ICAP divided by the \napplicable ELCC Class Rating of the Reference Resource for the remainder \nof the curve. \n \n \nFor the 2028/2029 Delivery Year, the Variable Resource Requirement \ncurve for the PJM Region shall be plotted by a horizontal line from the y-\naxis equal to the lesser of $256.75/MW-day ICAP divided by the applicable \nELCC Class Rating for the Reference Resource or the value of point 1, until \nsuch line intersects the curve that is based on the following: (i) a straight \nline connecting points (1) and (2), and (ii) a straight line connecting points \n(2) and (3), where: \n \n \nFor point (1), price equals: {the greater of [1.15 times Cost of New \nEntry minus 0.75 times the Net Energy and Ancillary Service \nRevenue Offset] or [0.2 times Cost of New Entry)]} divided by (the"},{"page":67,"startToken":22699,"endToken":23074,"text":"applicable ELCC Class Rating of the Reference Resource) and \nUnforced \nCapacity \nequals: \n[the \nPJM \nRegion \nReliability \nRequirement multiplied by 99%]; \n \n \nFor point (2), price equals: [0.5 times the price calculated for point \n1] divided by (the applicable ELCC Class Rating of the Reference \nResource) and Unforced Capacity equals: [the PJM Region \nReliability Requirement multiplied by 101.5%]; and \n \n \nFor point (3), price equals zero and Unforced Capacity equals: [the \nPJM Region Reliability Requirement multiplied by 106.0%]. \n \n \nOnce the horizontal line intersects the above curve, the Variable Resource \nRequirement Curve shall follow the lines that are based on the above points \nuntil the price reaches $138.25/MW-day ICAP divided by the applicable \nELCC Class Rating of the Reference Resource, at which point it shall be \nextended as a horizontal line at $138.25/MW-day ICAP divided by the \napplicable ELCC Class Rating of the Reference Resource for the remainder \nof the curve. \n \n \nFor the 2029/2030 Delivery Year, the Variable Resource Requirement \ncurve for the PJM Region shall be plotted by a horizontal line from the y-\naxis equal to the lesser of $256.75/MW-day ICAP divided by the applicable \nELCC Class Rating for the Reference Resource or the value of point 1, until \nsuch line intersects the curve that is based on the following: (i) a straight \nline connecting points (1) and (2), and (ii) a straight line connecting points \n(2) and (3), where: \n \n \nFor point (1), price equals: {the greater of [1.15 times Cost of New \nEntry minus 0.75 times the Net Energy and Ancillary Service \nRevenue Offset] or [0.2 times Cost of New Entry)]} divided by (the \napplicable ELCC Class Rating of the Reference Resource) and \nUnforced \nCapacity \nequals: \n[the \nPJM \nRegion \nReliability \nRequirement minus Excluded RTO New Large Load Amounts] \nmultiplied by 99%); \n \n \nFor point (2), price equals: [0.5 times the price calculated for point \n1] divided by (the applicable ELCC Class Rating of the Reference \nResource) and Unforced Capacity equals: [the PJM Region \nReliability Requirement minus Excluded RTO New Large Load \nAmounts] multiplied by 101.5%; and \n \n \nFor point (3), price equals zero and Unforced Capacity equals: [the \nPJM Region Reliability Requirement minus Excluded RTO New \nLarge Load Amounts] multiplied by 106.0%."},{"page":68,"startToken":23074,"endToken":23469,"text":" \nOnce the horizontal line intersects the above curve, the Variable Resource \nRequirement Curve shall follow the lines that are based on the above points \nuntil the price reaches $138.25/MW-day ICAP divided by the applicable \nELCC Class Rating of the Reference Resource, at which point it shall be \nextended as a horizontal line at $138.25/MW-day ICAP divided by the \napplicable ELCC Class Rating of the Reference Resource for the remainder \nof the curve. \n \n \nFor the 2030/2031 Delivery Year and for subsequent Delivery Years, the \nVariable Resource Requirement curve for the PJM Region shall be plotted \nby combining (i) a horizontal line from the y-axis to point (1), (ii) a straight \nline connecting points (1) and (2), and (iii) a straight line connecting points \n(2) and (3), where: \n \n \nFor point (1), price equals: {the greater of [1.15 times Cost of New \nEntry minus 0.75 times the Net Energy and Ancillary Service \nRevenue Offset] or [0.2 times Cost of New Entry)]} divided by (the \napplicable ELCC Class Rating of the Reference Resource) and \nUnforced \nCapacity \nequals: \n[the \nPJM \nRegion \nReliability \nRequirement minus Excluded RTO New Large Load Amounts] \nmultiplied by 99%]; \n \n \nFor point (2), price equals: [0.5 times the price calculated for point \n1] divided by (the applicable ELCC Class Rating of the Reference \nResource) and Unforced Capacity equals: [the PJM Region \nReliability Requirement minus Excluded RTO New Large Load \nAmounts] multiplied by 101.5%; and \n \n \nFor point (3), price equals zero and Unforced Capacity equals: [the \nPJM Region Reliability Requirement minus Excluded RTO New \nLarge Load Amounts] multiplied by 106.0%]. \n \nii) \nFor any Delivery Year, the Office of the Interconnection shall establish a \nseparate Variable Resource Requirement Curve for each LDA for which: \n \nA. \nthe Capacity Emergency Transfer Limit is less than 1.15 times the Capacity \nEmergency Transfer Objective, as determined by the Office of the \nInterconnection in accordance with NERC and Applicable Regional Entity \nguidelines; or \n \nB. \nsuch LDA had a Locational Price Adder in any one or more of the three \nimmediately preceding Base Residual Auctions; or \n \nC. \nsuch LDA is determined in a preliminary analysis by the Office of the \nInterconnection to be likely to have a Locational Price Adder, based on \nhistoric offer price levels; provided however that for the Base Residual \nAuction conducted for the Delivery Year, the Eastern Mid-Atlantic Region"},{"page":69,"startToken":23469,"endToken":23954,"text":"(“EMAR”), Southwest Mid-Atlantic Region (“SWMAR”), and Mid-\nAtlantic Region (“MAR”) LDAs shall employ separate Variable Resource \nRequirement Curves regardless of the outcome of the above three tests; and \nprovided further that the Office of the Interconnection may establish a \nseparate Variable Resource Requirement Curve for an LDA not otherwise \nqualifying under the above three tests if it finds that such is required to \nachieve an acceptable level of reliability consistent with the Reliability \nPrinciples and Standards, in which case the Office of the Interconnection \nshall post such finding, such LDA, and such Variable Resource \nRequirement Curve on its internet site no later than the March 31 last \npreceding the Base Residual Auction for such Delivery Year.  The same \nprocess as set forth in subsection (a)(i) shall be used to establish the Variable \nResource Requirement Curve for any such LDA, except that the Locational \nDeliverability Area Reliability Requirement for such LDA shall be \nsubstituted for the PJM Region Reliability Requirement and, beginning with \nthe 2029/2030 Delivery Year, the points on the LDA Variable Resource \nRequirement Curves will be reduced by the relevant Excluded LDA New \nLarge Load Amounts.  For purposes of calculating the Capacity Emergency \nTransfer Limit under this section, all generation resources located in the \nPJM Region that are, or that qualify to become, Capacity Resources, shall \nbe modeled at their full capacity rating, regardless of the amount of capacity \ncleared from such resource for the immediately preceding Delivery Year. \n \nFor Delivery Years up to and including the 2027/2028 Delivery Year for \neach such LDA, the Office of the Interconnection shall (a) determine the \nNet Cost of New Entry for each Zone in such LDA, with such Net Cost of \nNew Entry equal to the applicable Cost of New Entry value for such Zone \nminus the Net Energy and Ancillary Services Revenue Offset value for \nsuch Zone, and (b) compute the average of the Net Cost of New Entry \nvalues of all such Zones to determine the Net Cost of New Entry for such \nLDA.   \n \nFor the 2028/2029 Delivery Year and for subsequent Delivery Years for \neach such LDA, the Office of the Interconnection shall determine the \napplicable Cost of New Entry and Net Energy and Ancillary Services \nRevenue Offset value for each LDA, with such Cost of New Entry equal \nto the average of all five Cost of New Entry areas for RTO and the \naverage of the Cost of New Entry for all zones in an LDA, and the Net \nEnergy and Ancillary Services Revenue Offset value equal to the 67th \npercentile of the Net Energy and Ancillary Services Revenue Offset for all \nzones in such LDA. \n \niii) \nProcedure for ongoing review of Variable Resource Requirement Curve \nshape. \n \nBeginning with the Delivery Year that commences June 1, 2018, and continuing no later than for \nevery fourth Delivery Year thereafter, the Office of the Interconnection shall perform a review of"},{"page":70,"startToken":23954,"endToken":24351,"text":"the shape of the Variable Resource Requirement Curve, as established by the requirements of the \nforegoing subsection.  Such analysis shall be based on simulation of market conditions to \nquantify the ability of the market to invest in new Capacity Resources and to meet the applicable \nreliability requirements on a probabilistic basis.  Based on the results of such review, PJM shall \nprepare a recommendation to either modify or retain the existing Variable Resource Requirement \nCurve shape.  The Office of the Interconnection shall post the recommendation and shall review \nthe recommendation through the stakeholder process to solicit stakeholder input. If a \nmodification of the Variable Resource Requirement Curve shape is recommended, the following \nprocess shall be followed:   \n \nA) \nIf the Office of the Interconnection determines that the Variable \nResource Requirement Curve shape should be modified, Staff of \nthe Office of the Interconnection shall propose a new Variable \nResource Requirement Curve shape on or before May 15, prior to \nthe conduct of the Base Residual Auction for the first Delivery \nYear in which the new values would be applied.   \n \nB) \nThe PJM Members shall review the proposed modification to the \nVariable Resource Requirement Curve shape. \n \nC) \nThe PJM Members shall either vote to (i) endorse the proposed \nmodification, (ii) propose alternate modifications or (iii) \nrecommend no modification, by August 31, prior to the conduct of \nthe Base Residual Auction for the first Delivery Year in which the \nnew values would be applied. \n \nD) \nThe PJM Board of Managers shall consider a proposed \nmodification to the Variable Resource Requirement Curve shape, \nand the Office of the Interconnection shall file any approved \nmodified Variable Resource Requirement Curve shape with the \nFERC by October 1, prior to the conduct of the Base Residual \nAuction for the first Delivery Year in which the new values would \nbe applied. \n \niv) \nCost of New Entry  \n \nA) \nFor the Incremental Auctions, the Cost of New Entry for the PJM \nRegion and for each LDA shall be the respective value used in the \nBase Residual Auction for each corresponding Delivery Year and \nLDA.  For the Delivery Year commencing on June 1, 2022 through \nand including the Delivery Year commencing on June 1, 2025, the \nCost of New Entry for the PJM Region shall be the average of the \nCost of New Entry for each CONE Area listed in this section as \nadjusted pursuant to subsection (a)(iv)(B)."},{"page":71,"startToken":24351,"endToken":24687,"text":"Geographic Location Within the \nPJM Region Encompassing These \nZones \nCost of New Entry \nin $/MW-Year \nPS, JCP&L, AE, PECO, DPL, RECO \n(“CONE Area 1”) \n108,000 \nBGE, PEPCO (“CONE Area 2”) \n109,700 \nAEP, Dayton, ComEd, APS, DQL, \nATSI, DEOK, EKPC, Dominion, \nOVEC (“CONE Area 3”) \n105,500 \nPPL, MetEd, Penelec (“CONE Area \n4”) \n105,500 \n \nA-1)  Cost of New Entry for 2025/2026 Delivery Year \n \n \nA new CONE Area 5 encompassing only the ComEd Zone shall be \nestablished and the ComEd Zone will be removed from CONE \nArea 3.  For the 2025/2026 Delivery Year, the Cost of New Entry \nfor CONE Area 5 will be equal to the product of the Cost of New \nEntry determined for CONE Area 3 for the 2025/2026 Delivery \nYear multiplied by an asset life factor of 1.0069.  For the \n2025/2026 Delivery Year, the Cost of New Entry for the PJM \nRegion shall be the average of the Cost of New Entry for all \nCONE Areas. \n \nB) \nBeginning with the 2023/2024 Delivery Year through and including \nthe 2025/2026 Delivery Year, the CONE for each CONE Area \n(except for CONE Area 5) shall be adjusted to reflect changes in \ngenerating plant construction costs based on changes in the \nApplicable United States Bureau of Labor Statistics (“BLS”) \nComposite Index, and then adjusted further by a factor of 1.022 to \nreflect the annual decline in bonus depreciation scheduled under \nfederal corporate tax law, in accordance with the following:   \n \n \n(1) \nThe Applicable BLS Composite Index for any \nDelivery Year and CONE Area shall be the most \nrecently published twelve-month change, at the time \nCONE values are required to be posted for the Base \nResidual Auction for such Delivery Year, in a \ncomposite of the BLS Quarterly Census of \nEmployment and Wages for Utility System \nConstruction (weighted 20%), the BLS Producer \nPrice Index for Construction Materials and \nComponents (weighted 55%), and the BLS \nProducer Price Index Turbines and Turbine \nGenerator Sets (weighted 25%), as each such index"},{"page":72,"startToken":24687,"endToken":24978,"text":"is further specified for each CONE Area in the PJM \nManuals.  \n \n(2) \nThe CONE in a CONE Area shall be adjusted prior \nto the Base Residual Auction for each Delivery \nYear by applying the Applicable BLS Composite \nIndex for such CONE Area to the Benchmark \nCONE for such CONE Area, and then multiplying \nthe result by 1.022. \n \n(3) \nThe Benchmark CONE for a CONE Area shall be \nthe CONE used for such CONE Area in the Base \nResidual Auction for the prior Delivery Year \n(provided, however that the Gross CONE values \nstated in subsection (a)(iv)(A) above shall be the \nBenchmark CONE values for the 2022/2023 \nDelivery Year to which the Applicable BLS \nComposite Index shall be applied to determine the \nCONE for subsequent Delivery Years), and then \nmultiplying the result by 1.022.   \n \n(4) \nNotwithstanding the foregoing, CONE values for \nany CONE Area for any Delivery Year shall be \nsubject to amendment pursuant to appropriate \nfilings with FERC under the Federal Power Act, \nincluding, without limitation, any filings resulting \nfrom the process described in section 5.10(a)(vi)(C) \nor any filing to establish new or revised CONE \nAreas. \n \nC) \nFor the 2026/2027 Delivery Year and 2027/2028 Delivery Year, \nthe Cost of New Entry for the PJM Region shall be the average of \nthe Cost of New Entry for each CONE Area listed in this section as \nadjusted pursuant to subsection (a)(iv)(C)(1). \n \n \nGeographic Location Within the \nPJM Region Encompassing These \nZones \nCost of New Entry \n in $/MW-Year \n(ICAP) \nPS, JCP&L, AE, PECO, DPL, \nRECO (“CONE Area 1”) \n136,000 \nBGE, PEPCO (“CONE Area 2”) \n142,000 \nAEP, Dayton, APS, DQL, ATSI, \nDEOK, EKPC, \nDominion, OVEC (“CONE Area \n3”) \n147,600"},{"page":73,"startToken":24978,"endToken":25265,"text":"PPL, MetEd, Penelec (“CONE Area \n4”) \n143,500 \nComEd (“CONE Area 5”) \n150,800 \n \n(1) \nFor the 2027/2028 Delivery Year, the CONE for \neach CONE Area shall be adjusted to reflect \nchanges in generating plant construction costs based \non changes in the Applicable United States Bureau \nof Labor Statistics (“BLS”) Composite Index, in \naccordance with the following:  \n \n(a) \nThe Applicable BLS Composite Index for \nany Delivery Year and CONE Area shall \nbe the most recently published twelve-\nmonth change, at the time CONE values are \nrequired to be posted for the Base Residual \nAuction for such Delivery Year, in a \ncomposite of the BLS Quarterly Census of \nEmployment and Wages for Utility System \nConstruction (weighted 40%), the BLS \nProducer Price Index for Construction \nMaterials and Components (weighted 45%), \nand the BLS Producer Price Index Turbines \nand Turbine Generator Sets (weighted 15%), \nas each such index is further specified for \neach CONE Area in the PJM Manuals.  \n \n(b) \nFor CONE Areas 1 through 4, the \nBenchmark CONE for each CONE Area \nshall be the CONE used for such CONE \nArea in the Base Residual Auction for the \nprior Delivery Year (provided, however that \nthe Gross CONE values stated in subsection \n(a)(iv)(C) above shall be the Benchmark \nCONE values for the 2026/2027 Delivery \nYear to which the Applicable BLS \nComposite Index shall be applied to \ndetermine the CONE for subsequent \nDelivery Years). \n \n(c) \nFor the 2027/2028 Delivery Year, the \nCONE for CONE Area 5 for a given \nDelivery Year shall be set equal to the \nproduct of the CONE of CONE Area 3 as \ndetermined for the relevant Delivery Year in \naccordance with (a) and (b) above, \nmultiplied by the asset life factor applicable"},{"page":74,"startToken":25265,"endToken":25541,"text":"to that Delivery Year where such asset life \nfactors is 1.0376 for the 2027/2028 Delivery \nYear. \n \n(d) \nNotwithstanding the foregoing, CONE \nvalues for any CONE Area for any Delivery \nYear shall be subject to amendment pursuant \nto appropriate filings with FERC under the \nFederal Power Act, including, without \nlimitation, any filings resulting from the \nprocess described in section 5.10(a)(vi)(C) \nor any filing to establish new or revised \nCONE Areas.  \n \nD) \nFor the 2028/2029 Delivery Year and for subsequent Delivery \nYears, the Cost of New Entry for the PJM Region shall be the \naverage of the Cost of New Entry for each CONE Area listed in \nthis section. \n \n \n \nGeographic Location Within the \nPJM Region Encompassing These \nZones \nCost of New Entry \n in $/MW-Year \n(ICAP) \nPS, JCP&L, AE, PECO, DPL, \nRECO (“CONE Area 1”) \n218,000 \nBGE, PEPCO (“CONE Area 2”) \n222,000 \nAEP, Dayton, APS, DQL, ATSI, \nDEOK, EKPC, \nDominion, OVEC (“CONE Area \n3”) \n215,000 \nPPL, MetEd, Penelec (“CONE Area \n4”) \n216,000 \nComEd (“CONE Area 5”) \n248,000 \n \n(1) \nBeginning with the 2029/2030 Delivery Year, the Cost of \nNew Entry for each CONE Area shall be adjusted to reflect \nchanges in generating plant construction costs based on \nchanges in the Applicable United States Bureau of Labor \nStatistics (“BLS”) Composite Index, in accordance with the \nfollowing: \n \n(a) \nThe Applicable BLS Composite Index for any \nDelivery Year and CONE Area shall be the most \nrecently published twelve-month change, at the time \nCost of New Entry values are required to be posted \nfor the Base Residual Auction for such Delivery \nYear, in a composite of the Quarterly Census of"},{"page":75,"startToken":25541,"endToken":25906,"text":"Employment and Wages, which shall use  NAICS \n2371 Utility System Construction, Private, All \nEstablishment Sizes (weighted 15%), BLS Producer \nPrice Index for Commodities, Not Seasonally \nAdjusted, Intermediate Demand by Commodity \nType, Materials and Components for Construction \n(weighted 10%), BLS Producer Price Index for \nCommodities, Not Seasonally Adjusted, Machinery \nand Equipment, Turbines and Turbine Generator \nSets (weighted 46%), and the Bureau of Economic \nAnalysis: Gross Domestic Product Implicit Price \nDeflator, Index 2017=100, Seasonally Adjusted \n(weighted 29%), as each such index is further \nspecified for each CONE Area in the PJM Manuals. \n \n(b) \nFor CONE Areas 1 through 5, the Benchmark \nCONE for each CONE Area shall be the Cost of \nNew Entry used for such CONE Area in the Base \nResidual Auction for the prior Delivery Year \n(provided, however that the Cost of New Entry \nvalues stated in subsection (a)(iv)(C) above shall be \nthe Benchmark CONE values for the 2028/2029 \nDelivery Year to which the Applicable BLS \nComposite Index shall be applied to determine the \nCost of New Entry for subsequent Delivery Years). \n \n(c) \nFor the 2029/2030 Delivery Year through and \nincluding the 2031/2032 Delivery Year, the Cost of \nNew Entry for CONE Area 5 for a given Delivery \nYear shall be multiplied by the asset life factor \napplicable to that Delivery Year where such asset \nlife factors are 1.025 for the 2029/2030 Delivery \nYear, 1.054 for the 2030/2031 Delivery Year, and \n1.088 for the 2031/2032 Delivery Year. \n \nv) \nNet Energy and Ancillary Services Revenue Offset for 2023/2024 \nDelivery Year through and including the 2025/2026 Delivery Years \n(except that the calculation of the MOPR Floor Price pursuant to Tariff, \nAttachment DD, section 5.14(h-2) for combustion turbine resources shall \nremain applicable beyond the 2025/2026 Delivery Year): \n \nA) \nThe Office of the Interconnection shall determine the Net Energy \nand Ancillary Services Revenue Offset each year for  the PJM \nRegion as (A) the annual average of the revenues that would have \nbeen received by the Reference Resource from the PJM energy \nmarkets during a period of three consecutive calendar years \npreceding the time of the determination, based on (1) the heat rate"},{"page":76,"startToken":25906,"endToken":26358,"text":"and other characteristics of such Reference Resource; (2)  fuel \nprices reported during such period at an appropriate pricing point \nfor the PJM Region with a fuel transmission adder appropriate for \nsuch region, as set forth in the PJM Manuals, assumed variable \noperation and maintenance expenses for such resource of $6.93 per \nMWh, and actual PJM hourly average Locational Marginal Prices \nrecorded in the PJM Region during such period; and (3) an \nassumption that the Reference Resource would be dispatched for \nboth the Day-Ahead and Real-Time Energy Markets on a Peak-\nHour Dispatch basis; plus (B) ancillary service revenues of $2,199 \nper MW-year to be included through the 2025/2026 Delivery Year.   \n \nB)  \nThe Office of the Interconnection also shall determine a Net \nEnergy and Ancillary Service Revenue Offset each year for each \nZone, using the same procedures and methods as set forth in the \nprevious subsection; provided, however, that:  (1) the average \nhourly LMPs for such Zone shall be used in place of the PJM \nRegion average hourly LMPs; (2) if such Zone was not integrated \ninto the PJM Region for the entire applicable period, then the \noffset shall be calculated using only those whole calendar years \nduring which the Zone was integrated; and (3) a posted fuel pricing \npoint in such Zone, if available, and (if such pricing point is not \navailable in such Zone) a fuel transmission adder appropriate to \nsuch Zone from an appropriate PJM Region pricing point shall be \nused for each such Zone. \n \nv-1) \nNet Energy and Ancillary Services Revenue Offset for the 2026/2027 \nDelivery Year and subsequent Delivery Years: \n \nA) \nFor the 2026/2027 and the 2027/2028 Delivery Years, the Office \nof the Interconnection shall determine the Net Energy and \nAncillary Services Revenue Offset each year for the PJM Region \nas the average of the net energy and ancillary services revenues \nthat the Reference Resource is projected to receive from the PJM \nenergy and ancillary service markets for the applicable Delivery \nYear from three separate simulations, with each such simulation \nusing forward prices shaped using historical data from one of the \nthree consecutive calendar years preceding the time of the \ndetermination for the RPM Auction to take account of year-to-year \nvariability in such hourly shapes.  Each net energy and ancillary \nservices revenue simulation is based on (a) the heat rate and other \ncharacteristics of such Reference Resource such as assumed \nvariable operation and maintenance expenses of $1.19 per MWh \nand $21,170 per start-up, and emissions costs; (b) Forward Hourly \nLMPs for the PJM Region; (c) Forward Hourly Ancillary Services \nPrices, (d) Forward Daily Natural Gas Prices at an appropriate \npricing point for the PJM Region with a fuel transmission adder"},{"page":77,"startToken":26358,"endToken":26772,"text":"appropriate for such region, as set forth in the PJM Manuals; and \n(e) an assumption that the Reference Resource would be \ndispatched on a Projected EAS Dispatch basis.   \n \nA-1) \nFor the 2028/2029 and subsequent Delivery Years, the Office of \nthe Interconnection shall determine the Net Energy and Ancillary \nServices Revenue Offset each year for the PJM Region as the 67th \npercentile of all of the calculated zonal Net Energy and Ancillary \nServices Revenues Offsets that the Reference Resource is \nprojected to receive from the PJM energy and ancillary service \nmarkets for the applicable Delivery Year from three separate \nsimulations, with each such simulation using forward prices \nshaped using historical data from one of the three consecutive \ncalendar years preceding the time of the determination for the \nRPM Auction to take account of year-to-year variability in such \nhourly shapes.  Each Net Energy and Ancillary Service Revenue \nOffset simulation is based on (a) the heat rate and other \ncharacteristics of such Reference Resource such as assumed \nvariable operation and maintenance expenses of $2.65 per MWh, \nand emissions costs; (b) Forward Hourly LMPs for the PJM \nRegion; (c) Forward Hourly Ancillary Services Prices, (d) Forward \nDaily Natural Gas Prices at an appropriate pricing point for the \nPJM Region with a fuel transmission adder appropriate for such \nregion, as set forth in the PJM Manuals; and (e) an assumption that \nthe Reference Resource would be dispatched on a Projected EAS \nDispatch basis. \n \nB)  \nThe Office of the Interconnection also shall determine a Net \nEnergy and Ancillary Service Revenue Offset each year for each \nZone, using the same procedures and methods as set forth in the \nprevious subsection; provided, however, that:  (1) the Forward \nHourly LMPs for such Zone shall be used in place of the Forward \nHourly LMP for the PJM Region; (2) if such Zone was not \nintegrated into the PJM Region for the entire three calendar years \npreceding the time of the determination for the RPM Auction, then \nsimulations shall rely on only those whole calendar years during \nwhich the Zone was integrated; and (3) Forward Daily Natural Gas \nPrices for the fuel pricing point mapped to such Zone. \n \nC) \n“Forward Hourly LMPs” shall be determined as follows:  \n \n(1)  \nIdentify the liquid hub to which each Zone is mapped, as \nspecified in the PJM Manuals. \n \n(2)  \nFor each liquid hub, calculate the average day-ahead on-\npeak and day-ahead off-peak energy prices for each month \nduring the Delivery Year over the most recent thirty trading"},{"page":78,"startToken":26772,"endToken":27172,"text":"days as of 180 days prior to the Base Residual Auction.  \nFor each of the remaining steps, the historical prices used \nherein shall be taken from the most recent three calendar \nyears preceding the time of the determination for the RPM \nAuction: \n \n(3)  \nDetermine and add monthly basis differentials between the \nhub and each of its mapped Zones to the forward monthly \nday-ahead on-peak and off-peak energy prices for the hub. \nThis differential is developed using the prices for the \nPlanning Period closest in time to the Delivery Year from \nthe most recent long-term Financial Transmission Rights \nauction conducted prior to the Base Residual Auction. The \ndifference between the annual long-term Financial \nTransmission Rights auction prices for the Zone and the \nhub are converted to monthly values by adding, for each \nmonth of the year, the difference between (a) the historical \nmonthly average day-ahead congestion price differentials \nbetween the Zone and relevant hub and (b) the historical \nannual average day-ahead congestion price differentials \nbetween the Zone and hub. This step is only used when \ndeveloping forward prices for locations other than the \nliquid hubs;  \n \n(4)  \nDetermine and add marginal loss differentials to the \nforward monthly day-ahead on-peak and off-peak energy \nprices for the hub.  For each month of the year, calculate \nthe marginal loss differential, which is  the average of the \ndifference between the loss components of the historical on \npeak or off peak day-ahead LMPs for the Zone and relevant \nhub in that month across the three year period scaled by the \nratio of (a) the forward monthly average on-peak or off-\npeak day-ahead LMP at such hub to (b) the average of the \nhistorical on-peak or off-peak day-ahead LMPs for such \nhub in that month across the three year period.  This step is \nonly used when developing forward prices for locations \nother than the liquid hubs;  \n \n(5)  \nShape the forward monthly day-ahead on-peak and off-\npeak prices to (a) forward hourly day-ahead LMPs using \nhistoric hourly day-ahead LMP shapes for the Zone and (b) \nforward hourly real-time LMPs using historic hourly real-\ntime LMP shapes for the Zone. The historic hourly shapes \nare based on the ratio of the historic day-ahead or real-time \nLMP for the Zone for each given hour in a monthly on-\npeak or off-peak period to the average of the historic day-\nahead or real-time LMP for the Zone for all hours in such"},{"page":79,"startToken":27172,"endToken":27530,"text":"monthly on-peak or off-peak period. The historical prices \nused in this step shall be taken from one of each of the most \nrecent three calendar years preceding the time of the \ndetermination for the RPM Auction;  \n \n(6)  \nFor unit-specific energy and ancillary service offset \ncalculations, determine and apply basis differentials from \nthe Zone to the generation bus to the forward day-ahead \nand real-time hourly LMPs for the Zone.  The differential \nfor each hour of the year is developed using the difference \nbetween the historical DA or RT LMP for the generation \nbus and the historical DA or RT LMP for the Zone in \nwhich the generation bus is located for that same hour; and  \n \n(7)  \nDevelop the Forward Hourly LMPs for the PJM Region \npricing point. Calculate the load-weighted average of the \nmonthly on-peak and off-peak Zonal LMPs developed in \nstep (4) above, using the historical average load within each \nmonthly on-peak or off-peak period.  The load-weighted \naverage monthly on-peak or off-peak Zonal LMPs are then \nshaped to forward hourly day-ahead and real-time LMPs \nusing the same procedure as defined in step (5) above, \nexcept using historical LMPs for the PJM Region pricing \npoint.  \n \nD) \nForward Hourly Ancillary Services Prices shall include prices for \nSynchronized Reserve, Non-Synchronized Reserve and Secondary \nReserve and shall be determined as follows.  The historical prices \nused herein shall be taken from one of each of the most recent \nthree calendar years preceding the time of the determination for the \nRPM Auction: \n \n(1)  \nFor Synchronized Reserve, the forward real-time \nSynchronized Reserve market clearing price shall be \ncalculated by multiplying the historical RTO real-time \nhourly Synchronized Reserve market clearing price for \neach hour of the Delivery Year by the ratio of the real-time \nForward Hourly LMP at an appropriate pricing point, as \ndefined in the PJM manuals, to the historic hourly real-time \nLMP at such pricing point for the corresponding hour of the \nyear; \n \n(2)  \nFor Non-Synchronized Reserve, the forward real-time Non-\nSynchronized Reserve market clearing price shall be \ncalculated by multiplying the historical RTO real-time \nhourly Non-Synchronized Reserve market clearing price \nfor each hour of the Delivery Year by the ratio of the real-"},{"page":80,"startToken":27530,"endToken":27854,"text":"time Forward Hourly LMP at an appropriate pricing point, \nas defined in the PJM manuals, to the historic hourly real-\ntime LMP at such pricing point for the corresponding hour \nof the year; and \n \n(3)  \nFor Secondary Reserve, the forward day-ahead and real-\ntime Secondary Reserve market clearing price shall be \n$0.00/MWh for all hours. \n \nE) \nForward Daily Natural Gas Prices shall be determined as follows: \n \n(1)  \nMap each Zone to the appropriate natural gas hub in the \nPJM Region, as listed in the PJM Manuals; \n \n(2)  \nMap each natural gas hub lacking sufficient liquidity to the \nliquid hub to which it has the highest historic price \ncorrelation; \n \n(3)  \nFor each sufficiently liquid natural gas hub, calculate the \nsimple average natural gas monthly settlement prices over \nthe most recent thirty trading days as of 180 days prior to \nthe Base Residual Auction; \n \n(4)  \nCalculate the forward monthly prices for each illiquid hub \nby scaling the forward monthly price of the mapped liquid \nhub by the average ratio of historical monthly prices at the \ninsufficiently liquid hub to the historical monthly prices at \nthe sufficiently liquid over the most recent three calendar \nyears preceding the time of determination for the RPM \nAuction; \n \n(5)   \nShape the forward monthly prices for each hub to Forward \nDaily Natural Gas Prices using historic daily natural gas \nprice shapes for the hub. The historic daily shapes are \nbased on the ratio of the historic price for the hub for each \ngiven day in a month to the average of the historic prices \nfor the hub for all days in such month. The daily prices are \nthen assigned to each hour starting 10am Eastern Prevailing \nTime each day. The historical prices used in this step shall \nbe taken from one of each of the most recent three calendar \nyears preceding the time of the determination for the RPM \nAuction. \n \nvi) \nProcess for Establishing Parameters of Variable Resource Requirement \nCurve"},{"page":81,"startToken":27854,"endToken":28228,"text":"A) \nThe parameters of the Variable Resource Requirement Curve will \nbe established prior to the conduct of the Base Residual Auction \nfor a Delivery Year and will be used for such Base Residual \nAuction. \n \nB) \nThe Office of the Interconnection shall determine the PJM Region \nReliability Requirement and the Locational Deliverability Area \nReliability Requirement for each Locational Deliverability Area \nfor which a Variable Resource Requirement Curve has been \nestablished for such Base Residual Auction on or before February \n1, prior to the conduct of the Base Residual Auction for the first \nDelivery Year in which the new values will be applied, in \naccordance with the Reliability Assurance Agreement.  The \nVariable Resource Requirement Curve shall be posted on the same \ntimeline with the PJM Region Reliability Requirement and the \nLocational Deliverability Area Reliability Requirement. \nNotwithstanding, for the 2029/2030 Delivery Year, the updated \nVRR Curve that incorporates any Excluded RTO New Large Load \nAmounts and Excluded LDA New Large Load Amounts shall be \nposted one month prior to the commencement of the relevant RPM \nAuction. \n \nC) \nBeginning with the Delivery Year that commences June 1, 2018, \nand continuing no later than for every fourth Delivery Year \nthereafter, the Office of the Interconnection shall review the \ncalculation of the Cost of New Entry for each CONE Area.  \n \n1) \nIf the Office of the Interconnection determines that the Cost \nof New Entry values should be modified, the Staff of the \nOffice of the Interconnection shall propose new Cost of \nNew Entry values on or before May 15, prior to the conduct \nof the Base Residual Auction for the first Delivery Year in \nwhich the new values would be applied. \n \n2) \nThe PJM Members shall review the proposed values. \n \n3) \nThe PJM Members shall either vote to (i) endorse the \nproposed values, (ii) propose alternate values or (iii) \nrecommend no modification, by August 31, prior to the \nconduct of the Base Residual Auction for the first Delivery \nYear in which the new values would be applied. \n \n4) \nThe PJM Board of Managers shall consider Cost of New \nEntry values, and the Office of the Interconnection shall \nfile any approved modified Cost of New Entry values with \nthe FERC by October 1, prior to the conduct of the Base"},{"page":82,"startToken":28228,"endToken":28534,"text":"Residual Auction for the first Delivery Year in which the \nnew values would be applied. \n \nD) \nBeginning with the Delivery Year that commences June 1, 2018, \nand continuing no later than for every fourth Delivery Year \nthereafter, the Office of the Interconnection shall review the \nmethodology set forth in this Attachment for determining the Net \nEnergy and Ancillary Services Revenue Offset for the PJM Region \nand for each Zone. \n \n1) \nIf the Office of the Interconnection determines that the Net \nEnergy and Ancillary Services Revenue Offset \nmethodology should be modified, Staff of the Office of the \nInterconnection shall propose a new Net Energy and \nAncillary Services Revenue Offset methodology on or \nbefore May 15, prior to the conduct of the Base Residual \nAuction for the first Delivery Year in which the new \nmethodology would be applied.   \n \n2) \nThe PJM Members shall review the proposed methodology. \n \n3) \nThe PJM Members shall either vote to (i) endorse the \nproposed methodology, (ii) propose an alternate \nmethodology or (iii) recommend no modification, by \nAugust 31, prior to the conduct of the Base Residual \nAuction for the first Delivery Year in which the new \nmethodology would be applied. \n \n4) \nThe PJM Board of Managers shall consider the Net \nRevenue Offset methodology, and the Office of the \nInterconnection shall file any approved modified Net \nEnergy and Ancillary Services Revenue Offset values with \nthe FERC by October 1, prior to the conduct of the Base \nResidual Auction for the first Delivery Year in which the \nnew values would be applied.  \n \n \nb) \nLocational Requirements \n \nThe Office of Interconnection shall establish locational requirements prior to the Base Residual \nAuction to quantify the amount of Unforced Capacity that must be committed in each Locational \nDeliverability Area, in accordance with the Reliability Assurance Agreement. \n \nc) \n[Reserved] \n \nd) \nPreliminary PJM Region Peak Load Forecast for the Delivery Year"},{"page":83,"startToken":28534,"endToken":28626,"text":"The Office of the Interconnection shall establish the Preliminary PJM Region Load Forecast for \nthe Delivery Year in accordance with the PJM Manuals by February 1, prior to the conduct of the \nBase Residual Auction for such Delivery Year.   \n \n \ne) \nUpdated PJM Region Peak Load Forecasts for Incremental Auctions \n \nThe Office of the Interconnection shall establish the updated PJM Region Peak Load Forecast for \na Delivery Year in accordance with the PJM Manuals by February 1, prior to the conduct of the \nFirst, Second, and Third Incremental Auction for such Delivery Year."},{"page":84,"startToken":28626,"endToken":28995,"text":"5.11 \nPosting of Information Relevant to the RPM Auctions \n \n \na) \nIn accordance with the schedule provided in the PJM Manuals, PJM will post the \nfollowing information for a Delivery Year prior to conducting the Base Residual Auction for \nsuch Delivery Year: \n \ni) \nThe Preliminary PJM Region Peak Load Forecast (for the PJM Region, \nand allocated to each Zone); \n \nii) \nThe PJM Region Installed Reserve Margin, the Pool-wide average \nEFORd, (through the 2024/2025 Delivery Year), the pool-wide average Accredited UCAP \nFactor (beginning with the 2025/2026 Delivery Year), the Forecast Pool Requirement, and all \napplicable Capacity Import Limits; \n \niii) \nBeginning with the 2029/2030 Delivery Year, the quantity of Excluded \nRTO New Large Load Amounts and Excluded LDA New Large Load Amounts used in \nestablishing the Variable Resource Requirement Curve; \n \niv) \nThe PJM Region Reliability Requirement, and the Variable Resource \nRequirement Curve for the PJM Region, including the details of any adjustments to account for \nPrice Responsive Demand and any associated PRD Reservation Prices; \n \nv) \nThe Locational Deliverability Area Reliability Requirement and the \nVariable Resource Requirement Curve for each Locational Deliverability Area for which a \nseparate Variable Resource Requirement Curve has been established for such Base Residual \nAuction, including the details of any adjustments to account for Price Responsive Demand and \nany associated PRD Reservation Prices, and the CETO and CETL values for all Locational \nDeliverability Areas; \n \nvi) \nAny Transmission Upgrades that are expected to be in service for such \nDelivery Year, provided that a Transmission Upgrade that is Backbone Transmission satisfies \nthe project development milestones set forth in Tariff, Attachment DD, section 5.11A; \n \nvii) \nThe bidding window time schedule for each auction to be conducted for \nsuch Delivery Year; and \n \nviii) \nThe Net Energy and Ancillary Services Revenue Offset values for the \nPJM Region for use in the Variable Resource Requirement Curves for the PJM Region and each \nLocational Deliverability Area for which a separate Variable Resource Requirement Curve has \nbeen established for such Base Residual Auction. \n \n \nb) \nThe information listed in (a) will be posted and applicable for the First, Second, \nThird, and Conditional Incremental Auctions for such Delivery Year, except to the extent \nupdated or adjusted as required by other provisions of this Tariff."},{"page":85,"startToken":28995,"endToken":29442,"text":"c) \nIn accordance with the schedule provided in the PJM Manuals, PJM will post the \nFinal PJM Region Peak Load Forecast and the allocation to each zone of the obligation resulting \nfrom such final forecast, following the completion of the final Incremental Auction (including \nany Conditional Incremental Auction) conducted for such Delivery Year;  \n \n \nd) \nIn accordance with the schedule provided in the PJM Manuals, PJM will advise \nowners of Generation Capacity Resources of the updated EFORd values for such Generation \nCapacity Resources prior to the conduct of the Third Incremental Auction for such Delivery \nYear. \n \n \ne) \nAfter conducting the Reliability Pricing Model Auctions, PJM will post the results \nof each auction as soon thereafter as possible, including any adjustments to PJM Region or LDA \nReliability Requirements to reflect Price Responsive Demand with a PRD Reservation Price \nequal to or less than the applicable Base Residual Auction clearing price.  The posted results for \neach Base Residual Auction shall include graphical supply curves that are (a) provided for the \nentire PJM Region, (b) provided for any Locational Deliverability Area for which there are four \n(4) or more suppliers, and (c) developed using a formulaic approach to smooth the curves using a \nstatistical technique that fits a smooth curve to the underlying supply curve data while ensuring \nthat the point of intersection between supply and demand curves is at the market clearing price.   \n \nIf PJM discovers a potential error in the initial posting of auction results for a particular \nReliability Pricing Model Auction, it shall notify Market Participants as soon as possible after it \nis found, but in no event later than 5:00 p.m. of the fifth Business Day following the initial \npublication of the results of the auction.  After this initial notification, if PJM determines it is \nnecessary to post modified results, it shall provide notification of its intent to do so,  along with a \ndescription detailing the cause and scope of the error, by no later than 5:00 p.m. of the seventh \nBusiness Day following the initial publication of the results of the auction.  The provided \ndescription will not contain information that is market sensitive or confidential.  Thereafter, PJM \nmust post on its Web site any corrected auction results by no later than 5:00 p.m. of the tenth \nBusiness Day following the initial publication of the results of the auction. Should any of the \nabove deadlines pass without the associated action on the part of the Office of the \nInterconnection, the originally posted results will be considered final. Notwithstanding the \nforegoing, the deadlines set forth above shall not apply if the referenced auction results are under \npublicly noticed review by the FERC."},{"page":86,"startToken":29442,"endToken":29854,"text":"5.12 \nConduct of RPM Auctions \n \nThe Office of the Interconnection shall employ an optimization algorithm for each Base Residual \nAuction and each Incremental Auction to evaluate the Sell Offers and other inputs to such auction \nto determine the Sell Offers that clear such auction.   \n \n \na) \nBase Residual Auction  \n \nFor each Base Residual Auction, the optimization algorithm shall consider: \n \n \nall Sell Offers submitted in such auction; \n \n \nthe Variable Resource Requirement Curves for the PJM Region and each \nLDA; \n \n \nany constraints resulting from the Locational Deliverability Requirement \nand any applicable Capacity Import Limit; \n \n \nFor the 2018/2019 Delivery Year and subsequent Delivery Years, the PJM \nReliability Requirement; and \n \n \nFor the 2020/2021 Delivery Year and subsequent Delivery Years, the   \nrequirement that the cleared quantity of Summer-Period Capacity \nPerformance Resources equal the cleared quantity of Winter-Period \nCapacity Performance Resources for the PJM Region. \n \nThe optimization algorithm shall be applied to calculate the overall clearing result to minimize the \ncost of satisfying the reliability requirements across the PJM Region, regardless of whether the \nquantity clearing the Base Residual Auction is above or below the applicable target quantity, while \nrespecting all applicable requirements and constraints, including any restrictions specified in any \nCredit-Limited Offers.  Where the supply curve formed by the Sell Offers submitted in an auction \nfalls entirely below the Variable Resource Requirement Curve, the auction shall clear at the price-\ncapacity point on the Variable Resource Requirement Curve corresponding to the total Unforced \nCapacity provided by all such Sell Offers.  Where the supply curve consists only of Sell Offers \nlocated entirely below the Variable Resource Requirement Curve and Sell Offers located entirely \nabove the Variable Resource Requirement Curve, the auction shall clear at the price-capacity point \non the Variable Resource Requirement Curve corresponding to the total Unforced Capacity \nprovided by all Sell Offers located entirely below the Variable Resource Requirement Curve.  In \ndetermining the lowest-cost overall clearing result that satisfies all applicable constraints and \nrequirements, the optimization may select from among multiple possible alternative clearing \nresults that satisfy such requirements, including, for example (without limitation by such example), \naccepting a lower-priced Sell Offer that intersects the Variable Resource Requirement Curve and \nthat specifies a minimum capacity block, accepting a higher-priced Sell Offer that intersects the \nVariable Resource Requirement Curve and that contains no minimum-block limitations, or \nrejecting both of the above alternatives and clearing the auction at the higher-priced point on the \nVariable Resource Requirement Curve that corresponds to the Unforced Capacity provided by all"},{"page":87,"startToken":29854,"endToken":30225,"text":"Sell Offers located entirely below the Variable Resource Requirement Curve.  For the 2020/2021 \nDelivery Year and subsequent Delivery Years, the supply curve formed by the Sell Offers \nsubmitted within an LDA for which a separate VRR Curve is established, shall only consider the \nquantity of MW from Summer-Period Capacity Performance Resources that are equally matched \nwith Winter-Period Capacity Performance Resources within the LDA, such that only the equally \nmatched quantity of opposite-season Sell Offers are considered in satisfying the LDA’s reliability \nrequirement. \n \nThe Sell Offer price of a Qualifying Transmission Upgrade shall be treated as a capacity price \ndifferential between the LDAs specified in such Sell Offer between which CETL is increased, and \nthe Import Capability provided by such upgrade shall clear to the extent the difference in clearing \nprices between such LDAs is greater than the price specified in such Sell Offer.  The Capacity \nResource clearing results and Capacity Resource Clearing Prices so determined shall be applicable \nfor such Delivery Year.  The Capacity Resource clearing results and Capacity Resource Clearing \nPrices determined for Summer-Period Capacity Performance Resources shall be applicable for the \ncalendar months of June through October and the following May of such Delivery Year; and shall \nbe applicable for Winter-Period Capacity Performance Resources for the calendar months of \nNovember through April of such Delivery Year. \n \n \nb) \nScheduled Incremental Auctions. \n \n \nFor purposes of a Scheduled Incremental Auction, the optimization algorithm shall consider: \n \n  \nFor the 2018/2019 Delivery Year and subsequent Delivery Years, the PJM \nReliability Requirement; \n \n \nUpdated LDA Reliability Requirements taking into account any updated Capacity \nEmergency Transfer Objectives; \n \n \nThe Capacity Emergency Transfer Limit used in the Base Residual Auction, or any \nupdated value resulting from a Conditional Incremental Auction; \n \n \nAll applicable Capacity Import Limits; \n \n \nFor the 2018/2019 Delivery Year and subsequent Delivery Years, for each LDA, \nsuch LDA’s updated Reliability Requirement; \n \n \n \nFor the 2020/2021 Delivery Year and subsequent Delivery Years, the   requirement \nthat the cleared quantity of Summer-Period Capacity Performance Resources equal \nthe cleared quantity of Winter-Period Capacity Performance Resources for the PJM \nRegion; \n \n \nA demand curve consisting of the Buy Bids submitted in such auction and, if \nindicated for use in such auction in accordance with the provisions below, the \nUpdated VRR Curve Increment;"},{"page":88,"startToken":30225,"endToken":30806,"text":" \nThe Sell Offers submitted in such auction; and \n \n \nThe Unforced Capacity previously committed for such Delivery Year. \n \n(i) \nWhen the requirement to seek additional resource commitments in a \nScheduled Incremental Auction is triggered by Tariff, Attachment DD, section 5.4(c)(2), the \nOffice of the Interconnection shall employ in the clearing of such auction the Updated VRR Curve \nIncrement.      \n \n(ii) \nWhen the requirement to seek additional resource commitments in a \nScheduled Incremental Auction is triggered by Tariff, Attachment DD, section 5.4(c)(1), and the \nconditions stated in Tariff, Attachment DD, section 5.4(c)(2) do not apply, the Office of the \nInterconnection first shall determine the total quantity of (A) the amount that the Office of the \nInterconnection sought to procure in prior Scheduled Incremental Auctions for such Delivery Year \nthat does not clear such auction, minus (B) the amount that the Office of the Interconnection sought \nto sell back in prior Scheduled Incremental Auctions for such Delivery Year that does not clear \nsuch auction, plus (C) the difference between the updated PJM Region Reliability Requirement or \nupdated LDA Reliability Requirement (inclusive of any updated adjustments to the Excluded RTO \nNew Large Load Amounts and/or Excluded LDA New Large Load Amounts) and, respectively, \nthe PJM Region Reliability Requirement, or LDA Reliability Requirement (inclusive of any \nupdated adjustments to the Excluded RTO New Large Load Amounts and/or Excluded LDA New \nLarge Load Amounts), utilized in the most recent prior auction conducted for such Delivery Year \nplus any amount required by section 5.4(c)(2)(ii), plus (D) the reduction in Unforced Capacity \ncommitments associated with the transition provisions of Tariff, Attachment DD, section \n5.5A(c)(i)(B) and RAA, Schedule 6, section L.9.  If the result of such equation is a positive \nquantity, the Office of the Interconnection shall employ in the clearing of such auction a portion \nof the Updated VRR Curve Increment extending right from the left-most point on that curve in a \nmegawatt amount equal to that positive quantity defined above, to seek to procure such quantity.  \nIf the result of such equation is a negative quantity, the Office of the Interconnection shall employ \nin the clearing of the auction a portion of the Updated VRR Curve Decrement, extending and \nascending to the left from the right-most point on that curve in a megawatt amount corresponding \nto the negative quantity defined above, to seek to sell back such quantity.  \n \n (iii) \nWhen the possible need to seek agreements to release capacity \ncommitments in any Scheduled Incremental Auction is indicated for the PJM Region or any \nLDA by Tariff, Attachment DD, section 5.4(c)(3)(i), the Office of the Interconnection first shall \ndetermine the total quantity of (A) the amount that the Office of the Interconnection sought to \nprocure in prior Scheduled Incremental Auctions for such Delivery Year that does not clear such \nauction, minus (B) the amount that the Office of the Interconnection sought to sell back in prior \nScheduled Incremental Auctions for such Delivery Year that does not clear such auction, plus \n(C) the difference between the updated PJM Region Reliability Requirement or updated LDA \nReliability Requirement (inclusive of any updated adjustments to the Excluded RTO New Large \nLoad Amounts and/or Excluded LDA New Large Load Amounts) and, respectively, the PJM \nRegion Reliability Requirement, or LDA Reliability Requirement (inclusive of any updated \nadjustments to the Excluded RTO New Large Load Amounts and/or Excluded LDA New Large"},{"page":89,"startToken":30806,"endToken":31411,"text":"Load Amounts), utilized in the most recent prior auction conducted for such Delivery Year \nminus any capacity sell-back amount determined by PJM to be required for the PJM Region or \nsuch LDA by Tariff, Attachment DD, section 5.4(c)(3)(ii), plus (D) the reduction in Unforced \nCapacity commitments associated with the transition provisions of Tariff, Attachment DD, \nsection 5.5A(c)(i)(B) and RAA, Schedule 6, section L.9, provided, however, that the amount sold \nin total for all LDAs and the PJM Region related to a delay in a Backbone Transmission upgrade \nmay not exceed the amounts purchased in total for all LDAs and the PJM Region related to a \ndelay in a Backbone Transmission upgrade.  If the result of such equation is a positive quantity, \nthe Office of the Interconnection shall employ in the clearing of such auction a portion of the \nUpdated VRR Curve Increment extending right from the left-most point on that curve in a \nmegawatt amount equal to that positive quantity defined above, to seek to procure such quantity.  \nIf the result of such equation is a negative quantity, the Office of the Interconnection shall \nemploy in the clearing of the auction a portion of the Updated VRR Curve Decrement, extending \nand ascending to the left from the right-most point on that curve in a megawatt amount \ncorresponding to the negative quantity defined above, to seek to sell back such quantity.   \n \n(iv) \nIf none of the tests for adjustment of capacity procurement in subsections \n(i), (ii), or (iii) is satisfied for the PJM Region or an LDA in a Scheduled Incremental Auction, the \nOffice of the Interconnection first shall determine the total quantity of (A) the amount that the \nOffice of the Interconnection sought to procure in prior Scheduled Incremental Auctions for such \nDelivery Year that does not clear such auction, minus (B) the amount that the Office of the \nInterconnection sought to sell back in prior Scheduled Incremental Auctions for such Delivery \nYear that does not clear such auction.  If the result of such equation is a positive quantity, the \nOffice of the Interconnection shall employ in the clearing of such auction a portion of the Updated \nVRR Curve Increment extending right from the left-most point on that curve in a megawatt amount \nequal to that positive quantity defined above, to seek to procure such quantity.  If the result of such \nequation is a negative quantity, the Office of the Interconnection shall employ in the clearing of \nthe auction a portion of the Updated VRR Curve Decrement, extending and ascending to the left \nfrom the right-most point on that curve in a megawatt amount corresponding to the negative \nquantity defined above, to seek to sell back such quantity.   \n \n(v) \n (reserved) \n \n (vi) \nIf the above tests are triggered for an LDA and for another LDA wholly \nlocated within the first LDA, the Office of the Interconnection may adjust the amount of any Sell \nOffer or Buy Bids otherwise required by subsections (i), (ii), or (iii) above in one LDA as \nappropriate to take into account any reliability impacts on the other LDA.  \n \n (vii) The optimization algorithm shall calculate the overall clearing result to \nminimize the cost to satisfy the Unforced Capacity Obligation of the PJM Region to account for \nthe updated PJM Peak Load Forecast and the cost of committing replacement capacity in response \nto the Buy Bids submitted, while satisfying or honoring such reliability requirements and \nconstraints, in the same manner as set forth in subsection (a) above. \n \n (viii) Load Serving Entities may be entitled to certain credits (“Excess \nCommitment Credits”) under certain circumstances as follows:"},{"page":90,"startToken":31411,"endToken":31751,"text":"(A) \n[Reserved] \n \n(B) \nFor any Delivery Year beginning with the Delivery Year that commences \nJune 1, 2012, the total amount  that the Office of the Interconnection sought \nto sell back pursuant to subsection (b)(iii) above in the Scheduled \nIncremental Auctions for such Delivery Year that does not clear such \nauctions, less the total amount that the Office of the Interconnection sought \nto procure pursuant to subsections (b)(i) and (b)(ii) above in the Scheduled \nIncremental Auctions for such Delivery Years that does not clear such \nauctions, will be allocated to Load Serving Entities as set forth below;  \n \n(C) \nthe amount from (A) or (B) above for the PJM Region shall be allocated \namong Locational Deliverability Areas pro rata based on the reduction for \neach such Locational Deliverability Area in the peak load forecast from the \ntime of the Base Residual Auction to the time of the Third Incremental \nAuction; provided, however, that the amount allocated to a Locational \nDeliverability Area may not exceed the reduction in the corresponding \nReliability Requirement for such Locational Deliverability Area; and \nprovided further that any LDA with an increase in its load forecast shall not \nbe allocated any Excess Commitment Credits; \n \n(D) \nthe amount, if any, allocated to a Locational Deliverability Area shall be \nfurther allocated among Load Serving Entities in such areas that are charged \na Locational Reliability Charge based on the Daily Unforced Capacity \nObligation of such Load Serving Entities as of June 1 of the Delivery Year \nand shall be constant for the entire Delivery Year.  Excess Commitment \nCredits may be used as Replacement Capacity or traded bilaterally. \n \n \nc) \nConditional Incremental Auction   \n \nFor each Conditional Incremental Auction, the optimization algorithm shall consider: \n \n \nThe quantity and location of capacity required to address the identified reliability \nconcern that gave rise to the Conditional Incremental Auction;  \n \n \n \nAll applicable Capacity Import Limits; \n \n \nthe same Capacity Emergency Transfer Limits that were modeled in the Base \nResidual Auction, or any updated value resulting from a Conditional Incremental \nAuction; and  \n \n \nthe Sell Offers submitted in such auction."},{"page":91,"startToken":31751,"endToken":31999,"text":"The Office of the Interconnection shall submit a Buy Bid based on the quantity and location of \ncapacity required to address the identified reliability violation at a Buy Bid price equal to 1.5 times \nNet CONE.   \n \nThe optimization algorithm shall calculate the overall clearing result to minimize the cost to \naddress the identified reliability concern, while satisfying or honoring such reliability requirements \nand constraints. \n \n \nd) \nEqual-priced Sell Offers \n \nIf two or more Sell Offers submitted in any auction satisfying all applicable constraints include \nthe same offer price, and some, but not all, of the Unforced Capacity of such Sell Offers is required \nto clear the auction, then the auction shall be cleared in a manner that minimizes total costs, \nincluding total make-whole payments if any such offer includes a minimum block and, to the extent \nconsistent with the foregoing, in accordance with the following additional principles: \n \n1) \nas necessary, the optimization shall clear such offers that have a flexible \nmegawatt quantity, and the flexible portions of such offers that include a minimum block that \nalready has cleared, where some but not all of such equal-priced flexible quantities are required to \nclear the auction, pro rata based on their flexible megawatt quantities; and  \n \n2) \nwhen equal-priced minimum-block offers would result in equal overall \ncosts, including make-whole payments, and only one such offer is required to clear the auction, \nthen the offer that was submitted earliest to the Office of the Interconnection, based on its assigned \ntimestamp, will clear."},{"page":92,"startToken":31999,"endToken":32005,"text":"ATTACHMENT DD-4 \nINTERIM RESOURCE ADEQUACY SERVICE"},{"page":93,"startToken":32005,"endToken":32254,"text":"I. \nINTRODUCTION \n \nThis Attachment DD-4 sets forth the terms and conditions governing the provision of Interim \nResource Adequacy Service.  As more fully set forth in this Attachment and the PJM Manuals, \nand in conjunction with the Reliability Assurance Agreement: \n \n \n(a) \nInterim Resource Adequacy Service is a load reduction service, effective starting \nwith the 2027/2028 Delivery Year, through which Eligible New Large Loads may be compensated \nfor providing load reductions requested by the Office of the Interconnection to maintain system \nreliability for the purpose of supporting the integration of New Large Loads to the PJM Region \nthat are not in arrangements with new capacity additions to the PJM Region; \n \n \n(b) \nStarting with the 2027/2028 Delivery Year, the Office of the Interconnection may, \nin accordance with the Manuals, instruct the implementation of an Interim Resource Adequacy \nService Action prior to calling on Pre-Emergency Load Management Reductions Actions after \ndetermining that available economic real-time supply may not be sufficient to maintain reserves \nto meet applicable Reserve Requirements and/or Interconnection Reliability Operating Limits \nwithin prescribed limits and prevent cascading outages; \n \n(c) \nThe Large Load Registry maintained by the Office of the Interconnection, pursuant \nto the Reliability Assurance Agreement, shall inform which New Large Loads are eligible to be \ncalled on to provide Interim Resource Adequacy Service; and \n \n(d) \nThe Office of the Interconnection shall coordinate with Electric Distributors, and \nother Members as appropriate, on the provision of Interim Resource Adequacy Service and the \ncompensation for providing Interim Resource Adequacy Service."},{"page":94,"startToken":32254,"endToken":32367,"text":"II. \nRESPONSBILITIES OF THE OFFICE OF THE INTERCONNECTION  \n \nThe Office of the Interconnection shall: \n \n(a) \nmaintain the Large Load Registry, pursuant to Reliability Assurance Agreement, \nSchedule 11; \n \n(b) \nidentify Eligible New Large Loads;  \n \n(c) \ndetermine the megawatt quantity of New Large Loads eligible to provide Interim \nResource Adequacy Service in each Electric Distributor zone/area for a given \nDelivery Year;  \n \n(d) \nstarting with the 2027/2028 Delivery Year, issue an Interim Resource Adequacy \nService Action based on system conditions; and \n \n(e) \nrequest Electric Distributors to direct that a quantity of Eligible New Large Load \nAmounts in their respective zone(s)/area(s) be reduced in accordance with an \nInterim Resource Adequacy Service Action."},{"page":95,"startToken":32367,"endToken":32544,"text":"III. \nRESPONSBILITIES OF ELECTRIC DISTRIBUTORS \n \nElectric Distributors shall: \n \n(a)  \nexecute the Office of the Interconnection’s directives to implement Interim \nResource Adequacy Service Actions among the Eligible New Large Loads in the \nElectric Distributor’s zone/area, which is an area within a Zone for which the \nrelevant Electric Distributor specifies a separate Obligation Peak Load MW value \nand is a service area of an Electric Distributor that is a separately identifiable, \ngeographic area bounded by wholesale metering;  \n \n(b) \ncoordinate with the Office of the Interconnection in developing and maintaining the \nLarge Load Registry by providing the Office of the Interconnection any information \nor data the Electric Distributor believes appropriate to facilitate an accurate Large \nLoad Registry, including applicable state or RERRA retail tariff or contractual \nobligations;  \n \n(c) \ncoordinate, as appropriate, with the relevant state(s) or RERRA(s), individual Load \nServing Entities, and customers served by the Load Serving Entities in its zone/area \nto support transparent, effective, and orderly deployment of Interim Resource \nAdequacy Service; and \n \n(d) \nimplement compensation program consistent with Tariff, Attachment DD-4, \nsection X."},{"page":96,"startToken":32544,"endToken":32983,"text":"IV. \nDETERMINATION OF MAXIMUM INTERIM RESOURCE ADEQUACY \nSERVICE EACH ELIGIBLE NEW LARGE LOAD MAY PROVIDE IN A \nDELIVERY YEAR \n \n(a) \nAll Eligible New Large Loads shall be available to be requested to provide Interim \nResource Adequacy Service by the Office of the Interconnection.   \n \n(b) \nThe amount of Interim Resource Adequacy Service available to the Office of the \nInterconnection may change for each Delivery Year depending on the relationship of the amount \nof Capacity Resources committed, through Tariff, Attachment DD, for a given Delivery Year, and \nthe Eligible New Large Load Amounts. \n \n(i) \nIn the event ([the amount of Capacity Resources committed for a given Delivery \nYear (as determined after the Third Incremental Auction) is less than the PJM \nRegion Reliability Requirement determined prior to the Third Incremental Auction] \ndivided by the Pool-wide Accredited UCAP Factor) by an amount greater than the \nsum (in MW) of all Eligible New Large Load Amounts, then all Eligible New Large \nLoad Amounts is needed by the Office of the Interconnection to be available to \nprovide Interim Resource Adequacy Service for that Delivery Year;  \n \n(ii) \nIn the event ([the amount of Capacity Resources committed for a given Delivery \nYear (as determined after the Third Incremental Auction) is less than the PJM \nRegion Reliability Requirement determined prior to the Third Incremental Auction] \ndivided by the Pool-wide Accredited UCAP Factor) by an amount less than the sum \n(in MW) of all Eligible New Large Load Amounts, then the difference (in MW) \nshall be the cumulative amount (in MW) of Eligible New Large Load Amounts that \nthe Office of the Interconnection needs to be available to provide Interim Resource \nAdequacy Service for that Delivery Year; and \n \n(iii) \nIn the event ([the amount of Capacity Resources committed for a given Delivery \nYear (as determined after the Third Incremental Auction) equals or exceeds the \nPJM Region Reliability Requirement determined prior to the Third Incremental \nAuction] divided by the Pool-wide Accredited UCAP Factor), then the Office of \nthe Interconnection does not need any Eligible New Large Loads to be available to \nprovide Interim Resource Adequacy Service for that Delivery Year. \n \n(c) \nFor each Delivery Year that meets the requirements of Tariff, Attachment DD-4, sections \nIV(b)(i) or IV(b)(ii), the Office of the Interconnection shall determine:  \n \n(i) \nthe total amount of Interim Resource Adequacy Service (in MW) needed to be \navailable on a daily basis across the PJM Region for the Delivery Year; and  \n \n(ii) \nthe total amount of Interim Resource Adequacy Service (in MW) needed to be \navailable on a daily basis in each Electric Distributor zone/area for the Delivery \nYear, which shall be equal to"},{"page":97,"startToken":32983,"endToken":33042,"text":"the product of the sum of all Eligible New Large Load Amounts \nneeded in the PJM Region pursuant to Attachment DD-4, section \nIV(b) multiplied by the quotient of [(the sum of all Eligible New \nLarge Load Amounts in the Electric Distributor’s zone/area) divided \nby (the sum of all Eligible New Large Load Amounts in the PJM \nRegion)]."},{"page":98,"startToken":33042,"endToken":33301,"text":"V. \nDETERMINATION OF NEW LARGE LOADS ELIGIBILITY TO PROVIDE \nINTERIM RESOURCE ADEQUACY SERVICE \n \n(a) \nAll New Large Loads shall be Eligible New Large Loads to the extent that the sum of a \nNew Large Load’s Eligible New Large Load Amount is less than the New Large Load’s registered \npeak load (in MW), as provided in the Large Load Registry.  New Large Loads with a cumulative \ninstalled capacity equivalent of their BYONC arrangements and assigned Allocated RBP UCAP \nMW that equals or exceeds the New Large Load’s registered peak load, as provided in the Large \nLoad Registry, shall not be Eligible New Large Loads.  New Large Loads that are located within \nan FRR Service Area cannot be Eligible New Large Loads. \n \n(b) \nA New Large Load’s Eligible New Large Load Amount shall be determined as follows: \n \n(New Large Load’s registered peak load (in MW), as provided in the Large Load \nRegistry) minus (the sum of all BYONC arrangements with the New Large Load \nin accordance with Tariff, Attachment DD-4, section VII divided by the Forecast \nPool Requirement for the first Delivery Year in which the BYONC cleared an RPM \nAuction, plus Allocated RBP UCAP MW assigned to the New Large Load, in \naccordance with Tariff, Attachment DD-4, section IX divided by the Forecast Pool \nRequirement for the first Delivery Year in which the Allocated RBP UCAP MW \ncleared an RPM Auction). \n \n(c) \nFor purposes of removing its eligibility to provide Interim Resource Adequacy Service, a \nNew Large Load may enter into arrangements with BYONC supported by one or more resources."},{"page":99,"startToken":33301,"endToken":33684,"text":"VI. \nBRING YOUR OWN NEW CAPACITY CRITERIA \n \n(a) \n(i) \nCapacity Resources that cleared an RPM Auction for the first time in the Base \nResidual Auction for the 2027/2028, 2028/2029, and 2029/2030 Delivery Years may \nqualify as BYONC to the extent the underlying resource meets the criteria in subsection \n(b) below. \n \n(ii) \nMegawatts of Unforced Capacity that have not cleared an RPM Auction, other than \nthose specified in subsection (a)(i) above, may qualify as BYONC to the extent the \nunderlying resource meets the criteria in subsection (b) below.  To the extent three \nconsecutive Delivery Years meet the requirements of Tariff, Attachment DD-4, section \nIV(b)(iii), then megawatts of Unforced Capacity may qualify as BYONC to the extent the \nunderlying resource meets the criteria in subsection (b) below and such megawatts (1) have \nnot cleared in an RPM Auction conducted for a Delivery Year prior to the first Delivery \nYear for which the requirements of Tariff, Attachment DD-4, section IV(b)(iii) are not met \nand (2) meet the eligibility criteria set forth in Tariff, Attachment DD-4, section VI. \n \n(iii) \nWith the exception of the RPM Auctions listed in subsection (a)(i) above, to the \nextent megawatts of Unforced Capacity that have cleared an RPM Auction before any \narrangement with a New Large Load based on such megawatts was reported to the Office \nof the Interconnection, then such megawatts of Unforced Capacity cannot qualify as \nBYONC even if the underlying resource meets the criteria in subsection (b) below. \n \n(b) \nTo qualify as Bring Your Own New Capacity, resources must meet the following eligibility \nrequirements: \n \n(i) \nFor generation and storage resources, the resource must be supported by one of the \nfollowing: \n \n(1) \na new-build generation resource including new resources that obtain \nCapacity Interconnection Rights transferred from deactivated resources or \nresources that have announced deactivation as of April 10, 2026; \n \n(2) \nthe incremental capacity created by an uprate of Existing Generation \nCapacity Resources, but only to the extent such incremental capacity is \ncreated through an increase in such Generation Capacity Resource’s \ninstalled capacity and increase in Capacity Interconnection Rights \nassociated with that Generation Capacity Resource;  \n \n(3) \nthe incremental capacity created by the utilization of Surplus \nInterconnection Service;  \n \n(4) \nrepowering of a deactivated generation resource that deactivated prior to \nApril 10, 2026; or"},{"page":100,"startToken":33684,"endToken":33954,"text":"(5) \nincremental capacity, whether due to greater Unforced Capacity or a higher \nlevel of Capacity Interconnection Rights, created by an Existing Generation \nCapacity Resource’s changing fuel type to a more efficient fuel type. \n \n(ii) \nFor Demand Resources or DER Capacity Aggregation Resources, the resource \nmust qualify as a Planned Demand Resource or DER Capacity Aggregation Resource, as \ndescribed in the RAA, Schedule 6 and Schedule 6.2 and:  \n \n(1) \nbe composed of, or reliant on, any location not registered in or prior to the \n2026/2027 Delivery Year at which an incremental amount at that location \nis the result of the registration of new generation or storage assets at the \nlocation. However, to the extent three consecutive Delivery Years meet the \nrequirements of Tariff, Attachment DD-4, section IV(b)(iii), then will be \ncomposed of, or reliant on, any location registered in the Delivery Year \nprior to the first Delivery Year for which the requirements of Tariff, \nAttachment DD-4, section IV(b)(iii) are not met; and/or \n \n(2) \nbe composed of, or reliant on, locations that were not previously supported \na Capacity Resource, a Peak Shaving Adjustment, or Price Responsive \nDemand for or prior to the 2026/2027 Delivery Year. However, to the extent \nthree consecutive Delivery Years meet the requirements of Tariff, \nAttachment DD-4, section IV(b)(iii), then will be composed of, or reliant \non, locations that were not previously supported a Capacity Resource, a \nPeak Shaving Adjustment, or Price Responsive Demand for the Delivery \nYear prior to the first Delivery Year for which the requirements of Tariff, \nAttachment DD-4, section IV(b)(iii) are not met."},{"page":101,"startToken":33954,"endToken":34457,"text":"VII. \nBRING YOUR OWN NEW CAPACITY ARRANGEMENTS WITH NEW LARGE \nLOADS \n \n(a) \nFor any BYONC to be in an arrangement with a New Large Load,  \n \n(i) \nthe Load Serving Entity serving the New Large Load or the applicable Electric \nDistributor shall report the BYONC in an arrangement with the New Large Load, in \naccordance with the PJM Manuals.  The Office of the Interconnection may also accept \ninformation to the extent interconnection customers, Large Loads, Transmission Owners, \nor other entities voluntarily report any BYONC that may be in an arrangement with a New \nLarge Load; and    \n \n(ii) \nthe resource owner or entity with contractual authority to enter into a BYONC \narrangement must certify to the Office of Interconnection, in accordance with the PJM \nManuals, attesting to the arrangement with the New Large Load and that the BYONC will \nfollow the requirements of Tariff, Attachment DD-4, section VIII. \n \n(b) \nFor an arrangement between a New Large Load and BYONC to be effective for the \n2027/2028 and 2028/2029 Delivery Years, for any BYONC arrangement to be considered, the \nrequirements of Tariff, Attachment DD-4, section VII(a) must be met by April 1 for the first \nDelivery Year such arrangement is to result in a reduction in the New Large Load’s Eligible New \nLarge Load Amount.  By April 15, the Office of the Interconnection shall update the Large Load \nRegistry to reflect any verified arrangements between New Large Loads and BYONC.   \n \n(c) \nFor an arrangement between a New Large Load and BYONC to be effective for the \n2029/2030 Delivery Year, for any BYONC arrangement to be considered, the requirements of \nTariff, Attachment DD-4, section VII(a) must be reported to the Office of the Interconnection no \nlater than by 50 days prior to the commencement of the 2029/2030 Base Residual Auction or by \n30 days prior to the posting of the planning parameters for the Incremental Auctions arrangement \nfor the 2029/2030 Delivery Year.  The Office of the Interconnection shall update the Large Load \nRegistry to reflect any verified arrangements between New Large Loads and BYONC after the \nrelevant RPM Auction. \n \n(d) \nFor an arrangement between a New Large Load and BYONC to be effective for the \n2030/2031 Delivery Year and subsequent Delivery Years, the requirements of Tariff, Attachment \nDD-4, section VII(a) must be reported to the Office of the Interconnection no later than by 30 days \nprior to the posting of the planning parameters for the relevant RPM Auction for the initial Delivery \nYear the BYONC enters into an arrangement with the New Large Load.  The Office of the \nInterconnection shall update the Large Load Registry to reflect any verified arrangements between \nNew Large Loads and BYONC after the relevant RPM Auction. \n \n(e) \nBYONC that is in an arrangement with a New Large Load must remain in such \narrangement with that New Large Load unless and until the New Large Load is permanently out-\nof-service. \n \n(f) \nA physical resource may support multiple BYONC, each of which may be in an"},{"page":102,"startToken":34457,"endToken":34719,"text":"arrangement with different New Large Loads, as long as no BYONC is in an arrangement with \nmore than one New Large Load. \n \n(g) \nA New Large Load may enter into an arrangement with discrete BYONC supported by \ndifferent physical resources. \n \n(h) \nA New Large Load may enter into an arrangement with BYONC in excess of its current \nEligible Large Load Amount, e.g., to allow for expected growth in the New Large Load, and the \nfull megawatt quantity of such BYONC shall be offered in the first RPM Auction for which the \nNew Large Load is included in the Variable Resource Requirement Curve. \n \n(i) \n(i) \nFor any generation or storage resource, the Accredited UCAP of any BYONC shall \nbe the Accredited UCAP for the RPM Auction in which the BYONC cleared for the initial \nDelivery Year the BYONC is in an arrangement with the New Large Load.  \n \n(ii) \nFor Demand Resources or DER Capacity Aggregation Resources, the Accredited \nUCAP shall be the Accredited UCAP for the RPM Auction in which the BYONC cleared \nfor the initial Delivery Year the BYONC is in an arrangement with the New Large Load \nand must be demonstrated each year for a 10-year period using the Demand Response or \nDER Capacity Aggregation Resources installed capacity for the first Delivery Year after \nthe BYONC is in an arrangement with the New Large Load.  For Demand Resources or \nDER Capacity Aggregation Resources that are also the actual New Large Load, there is no \ndemonstration required for the initial Delivery Year only to not be an Eligible New Large \nLoad."},{"page":103,"startToken":34719,"endToken":35164,"text":"VIII. BRING YOUR OWN NEW CAPACITY PARTICIPATION IN THE RELIABILITY \nPRICING MODEL \n \n(a) \nAll BYONC in an arrangement with a New Large Load must meet the requirements in \nTariff, Attachment DD, section 5.5A and become Capacity Resources eligible to participate in \nRPM Auctions.   \n \n(b) \nAll BYONC in an arrangement with a New Large Load must be offered into the RPM \nAuctions as Capacity Resources consistent with and pursuant to the capacity must-offer \nrequirements and exceptions set forth in Tariff, Attachment DD, sections 6.6 and 6.6A.  BYONC \nmay not seek an exception to the capacity must-offer requirement to provide an external sale, as \navailable under Tariff, Attachment DD, section 6.6(g) for a 10-year period starting with the first \nDelivery Year which the BYONC is in an arrangement with the New Large Load. \n \n(c) \nAll BYONC in an arrangement with a New Large Load and committed through RPM \nAuctions will be subject to all capacity market rules, as set forth in Tariff, Attachments DD and \nDD-1.   \n \n(d) \nTo the extent the resource supporting a BYONC arrangement is unavailable in a given \nDelivery Year, the seller of such resource will be subject to all relevant deficiency charges under \nTariff, Attachment DD. \n \n(e)  \nAll BYONC in an arrangement with a New Large Load and not qualifying for an exception \npursuant to Tariff, Attachment DD, section 6.6(g), must be offered into the applicable RPM \nAuctions as price takers, i.e., $0/MW-day UCAP for a 10-year period starting with the first \nDelivery Year which the BYONC is in an arrangement with the New Large Load. To the extent \nthe resource is a Demand Resource or DER Capacity Aggregation Resource, the BYONC shall \nparticipate in RPM Auctions for ten (10) consecutive Delivery Years as an Annual Demand \nResource or DER Capacity Aggregation Resource, as applicable; provided, however, the seller of \nsuch Demand Resource or DER Capacity Aggregation Resource may, in accordance with Tariff, \nAttachment DD-4, section VII(a)(i) report to the Office of the Interconnection BYONC that \nreplaces such BYONC, where such replacement shall be for the remainder of the replaced \nBYONC’s ten-year RPM Auction participation commitment and the replaced BYONC (and its \nsupporting registrations) may no longer provide BYONC.  In such event, the replacement BYONC \nwould need to be supported by the certification required by Tariff, Attachment DD-4, section \nVII(a)(ii), and such replacement arrangement must be effective coincident with the initial BYONC \nreleasing its arrangement.  \n \n(f) \nTo the extent three consecutive Delivery Years meet the requirements of Tariff, \nAttachment DD-4, section IV(b)(iii), then any existing BYONC are relieved of the obligations \nunder this Tariff, Attachment DD-4, section VIII."},{"page":104,"startToken":35164,"endToken":35349,"text":"IX. \nALLOCATION OF RBP UCAP MW  \n \n(a) \nEach Electric Distributor zone/area allocated RBP Charges pursuant to Tariff, Attachment \nDD, section 18.3(a) shall be allocated RBP UCAP MW on a pro-rata basis using the Electric \nDistributor zone/area’s assigned share of the total Final RBP Target MW across all zone/areas. \n \n(b) \nEach New Large Load’s Allocated RBP UCAP MW shall be determined as follows: \n \n(i) \nEach Electric Distributor allocated RBP UCAP MW shall inform the Office of the \nInterconnection how such RBP UCAP MW should be further allocated among the New \nLarge Loads located in the Electric Distributor’s zone/area; or  \n \n(ii) \nIn the event the Electric Distributor has not informed the Office of the \nInterconnection how its RBP UCAP MW should be further allocated by April 1 before a \ngiven Delivery Year, the Office of the Interconnection shall allocate such RBP UCAP MW \nto the Electric Distributor’s zone/area pro-rata among all New Large Loads located in the \nzone/area.  \n \n(c) \nThe Office of the Interconnection shall list in the Large Load Registry each New Large \nLoad’s Allocated RBP UCAP MW."},{"page":105,"startToken":35349,"endToken":35827,"text":"X. \nCOMPENSATION FOR PROVIDING INTERIM RESOURCE ADEQUACY \nSERVICE  \n \n(a) \nThe rate for the provision of Interim Resource Adequacy Service shall be 50% of the Non-\nPerformance Charge Rate specified in Tariff, Attachment DD, section 10A(e), unless any Eligible \nNew Large Load elects to (i) accept in its retail rates a sum less than 50% of the Non-Performance \nCharge Rate as compensation for the provision of wholesale Interim Resource Adequacy Service, \nor (ii) waive receipt in its retail rates any compensation for the provision of wholesale Interim \nResource Adequacy Service as contemplated by Tariff, Attachment DD-4, section X(c).  If any \nEligible New Large Load so elects to accept less than 50% of the Non-Performance Charge Rate \nor waives in its entirety receipt of compensation for the provision of wholesale Interim Resource \nAdequacy Service, the wholesale rate for the provision of Interim Resource Adequacy Service \nshall reflect the accepted sum less than 50% of the Non-Performance Charge Rate or if \ncompensation is waived entirely, the rate shall be zero dollars.   \n \n(b) \n(i) \nFollowing an Interim Resource Adequacy Event, unless the Electric Distributor \ninforms the Office of the Interconnection otherwise in accordance with Tariff, Attachment \nDD-4, section X(b)(ii), the Electric Distributor shall be responsible for compensating all \nEligible New Large Loads that provided Interim Resource Adequacy Service for up to the \namount of such service provided.  The Electric Distributor shall be responsible for charging \ncustomers in its zone/area to fund any such compensation.  \n \n(ii) \nThe Electric Distributor may request the Office of the Interconnection to \ncompensate certain Members for the provision of Interim Resource Adequacy Service and \nto assess charges on certain Load Serving Entities within the Electric Distributor’s \nzone/area to fund such compensation.  In support of such request, as further set forth in the \nPJM Manuals, the Electric Distributor shall (1) identify each Member to be compensated \nand provide the level of compensation and (2) identify each Load Serving Entity to be \ncharged and the level of charge. \n \n(iii) \nThe Office of the Interconnection, PJMSettlement, and the Members will not \nassume financial responsibility for the failure of a party to pay any amounts owed to \nanother party under this section.  In the event the Electric Distributor requests the Office \nof the Interconnection facilitate the billing associated with an Interim Resource Adequacy \nEvent, such billing shall be considered a bilateral transaction between the Electric \nDistributor and the identified Members and PJMSettlement shall not be a contracting party \nto the settlement. \n \n(c) \nNothing in this Tariff, Attachment DD-4, section X shall interfere with any Eligible New \nLarge Load’s election to (i) accept in its retail rates a sum less than 50% of the Non-Performance \nCharge Rate as compensation for the provision of wholesale Interim Resource Adequacy Service, \nor (ii) waive receipt in its retail rates any compensation for the provision of wholesale Interim \nResource Adequacy Service."},{"page":106,"startToken":35827,"endToken":36239,"text":"ARTICLE 1 – DEFINITIONS \n \n \nUnless the context otherwise specifies or requires, capitalized terms used herein shall \nhave the respective meanings assigned herein or in the Schedules hereto, or in the PJM Tariff or \nPJM Operating Agreement if not otherwise defined in this Agreement, for all purposes of this \nAgreement (such definitions to be equally applicable to both the singular and the plural forms of \nthe terms defined).  Unless otherwise specified, all references herein to Articles, Sections or \nSchedules, are to Articles, Sections or Schedules of this Agreement. As used in this Agreement: \n \n \nAccredited UCAP: \n \n“Accredited UCAP” shall mean the quantity of Unforced Capacity, as denominated in Effective \nUCAP, that an ELCC Resource is capable of providing in a given Delivery Year. \n \nAccredited UCAP Factor: \n \n“Accredited UCAP Factor” shall mean, through the 2024/2025 Delivery Year, one minus \nEFORd, and for 2025/2026 Delivery Year and subsequent Delivery Years, the ratio of the \nCapacity Resource’s Accredited UCAP to the Capacity Resource’s installed capacity. \n \nAgreement: \n \n \n“Agreement” shall mean this Reliability Assurance Agreement, together with all Schedules \nhereto, as amended from time to time. \n \nAnnual Demand Resource: \n \n“Annual Demand Resource” shall mean a resource that is placed under the direction of the \nOffice of the Interconnection  during the Delivery Year, and will be available for an unlimited \nnumber of interruptions during such Delivery Year by the Office of the Interconnection, and will \nbe capable of maintaining each such interruption between the hours of 10:00AM to 10:00PM \nEastern Prevailing Time for the months of June through October and the following May, and \n6:00AM through 9:00PM Eastern Prevailing Time for the months of November through April \nunless there is an Office of the Interconnection approved maintenance outage during October \nthrough April.  The Annual Demand Resource must be available in the corresponding Delivery \nyear to be offered for sale or Self-Supplied in an RPM Auction, or included as an Annual \nDemand Resource in an FRR Capacity Plan for the corresponding Delivery Year. \n \nAnnual Energy Efficiency Resource: \n \n“Annual Energy Efficiency Resource” shall mean a project, including installation of more \nefficient devices or equipment or implementation of more efficient processes or systems, \nmeeting the requirements of  Reliability Assurance Agreement, Schedule 6 and exceeding then-\ncurrent building codes, appliance standards, or other relevant standards, designed to achieve a \ncontinuous (during the summer and winter periods described in such Schedule 6 and the PJM \nManuals) reduction in electric energy consumption that is not reflected in the peak load forecast"},{"page":107,"startToken":36239,"endToken":36634,"text":"prepared for the Delivery Year for which the Energy Efficiency Resource is proposed, and that is \nfully implemented at all times during such Delivery Year, without any requirement of notice, \ndispatch, or operator intervention. \n \nApplicable Regional Entity: \n \n \n“Applicable Regional Entity” shall have the same meaning as in the PJM Tariff.   \n \nBase Capacity Demand Resource: \n \n“Base Capacity Demand Resource” shall mean, for the 2018/2019 and 2019/2020 Delivery \nYears, a resource that is placed under the direction of the Office of the Interconnection and that \nwill be available June through September of a Delivery Year, and will be available to the Office \nof the Interconnection for an unlimited number of interruptions during such months, and will be \ncapable of maintaining each such interruption for at least a 10-hour duration between the hours \nof 10:00AM to 10:00PM Eastern Prevailing Time.  The Base Capacity Demand Resource must \nbe available June through September in the corresponding Delivery Year to be offered for sale or \nself-supplied in an RPM Auction, or included as a Base Capacity Demand Resource in an FRR \nCapacity Plan for the corresponding Delivery Year.   \n \nBase Capacity Energy Efficiency Resource:  \n \n“Base Capacity Energy Efficiency Resource” shall mean, for the 2018/2019 and 2019/2020 \nDelivery Years, a project, including installation of more efficient devices or equipment or \nimplementation of more efficient processes or systems, meeting the requirements of RAA, \nSchedule 6 and exceeding then-current building codes, appliance standards, or other relevant \nstandards, designed to achieve a continuous (during the summer peak periods as described in \nReliability Assurance Agreement, Schedule 6 and the PJM Manuals) reduction in electric energy \nconsumption that is not reflected in the peak load forecast prepared for the Delivery Year for \nwhich the Base Capacity Energy Efficiency Resource is proposed, and that is fully implemented \nat all times during such Delivery Year, without any requirement of notice, dispatch, or operator \nintervention. \n \nBase Capacity Resource:  \n \n“Base Capacity Resource” shall have the same meaning as in Tariff, Attachment DD. \n \nBase Residual Auction: \n \n \n“Base Residual Auction” shall have the same meaning as in Tariff, Attachment DD. \n \n \nBehind The Meter Generation: \n \n \n“Behind The Meter Generation” shall refer to a generating unit that delivers energy to load \nwithout using the Transmission System or any distribution facilities (unless the entity that owns \nor leases the distribution facilities consented to such use of the distribution facilities and such"},{"page":108,"startToken":36634,"endToken":37085,"text":"consent has been demonstrated to the satisfaction of the Office of the Interconnection; provided, \nhowever, that Behind The Meter Generation does not include (i) at any time, any portion of such \ngenerating unit’s capacity that is designated as a Generation Capacity Resource or DER Capacity \nAggregation Resource or (ii) in any hour, any portion of the output of such generating unit that is \nsold to another entity for consumption at another electrical location or into the PJM Interchange \nEnergy Market. \n \n \nBlack Start Capability: \n \n \n“Black Start Capability” shall mean the ability of a generating unit or station to go from a \nshutdown condition to an operating condition and start delivering power without assistance from \nthe power system. \n \n \nBring Your Own New Capacity: \n \n“Bring Your Own New Capacity” or “BYONC” shall have the meaning provided in the Tariff. \n \nCapacity Emergency Transfer Objective (CETO): \n \n \n“Capacity Emergency Transfer Objective” or “CETO” shall mean, through the 2024/2025 \nDelivery Year, the amount of electric energy that a given area must be able to import in order to \nremain within a loss of load expectation of one event in 25 years when the area is experiencing a \nlocalized capacity emergency, as determined in accordance with the PJM Manuals.  Without \nlimiting the foregoing, CETO shall be, for Delivery Years through 2024/2025, calculated based \nin part on EFORD determined in accordance with Reliability Assurance Agreement, Schedule 5, \nParagraph C. Beginning with the 2025/2026 Delivery Year, CETO shall mean the amount of \nelectric energy that a given area must be able to import in order to satisfy a normalized expected \nunserved energy for the area that is equal to forty percent of the normalized expected unserved \nenergy for the RTO when at the annual reliability criteria, where normalized expected unserved \nenergy is the expected unserved energy (for the area or RTO, as appropriate) divided by  the \nforecasted annual energy (for the area or RTO, as appropriate), when the area is experiencing a \nlocalized capacity emergency, as determined in accordance with the PJM Manuals. \n \n \nCapacity Emergency Transfer Limit (CETL): \n \n \nCapacity Emergency Transfer Limit” or “CETL” shall mean the capability of the transmission \nsystem to support deliveries of electric energy to a given area experiencing a localized capacity \nemergency as determined in accordance with the PJM Manuals. \n \n \nCapacity Import Limit: \n \nFor any Delivery Year up to and including the 2019/2020 Delivery Year, “Capacity Import \nLimit” shall mean, (a) for the PJM Region, (1) the maximum megawatt quantity of external \nGeneration Capacity Resources that PJM determines for each Delivery Year, through appropriate \nmodeling and the application of engineering judgment, the transmission system can receive, in \naggregate at the interface of the PJM Region with all external balancing authority areas and"},{"page":109,"startToken":37085,"endToken":37696,"text":"deliver to load in the PJM Region under capacity emergency conditions without violating \napplicable reliability criteria on any bulk electric system facility of 100kV or greater, internal or \nexternal to the PJM Region, that has an electrically significant response to transfers on such \ninterface, minus (2) the then-applicable Capacity Benefit Margin; and (b) for certain source \nzones identified in the PJM manuals as groupings of one or more balancing authority areas, (1) \nthe maximum megawatt quantity of external Generation Capacity Resources that PJM \ndetermines the transmission system can receive at the interface of the PJM Region with each \nsuch source zone and deliver to load in the PJM Region under capacity emergency conditions \nwithout violating applicable reliability criteria on any bulk electric system facility of 100kV or \ngreater, internal or external to the PJM Region, that has an electrically significant response to \ntransfers on such interface, minus the then-applicable Capacity Benefit Margin times (2) the ratio \nof the maximum import quantity from each such source zone divided by the PJM total maximum \nimport quantity.  As more fully set forth in the PJM Manuals, PJM shall make such \ndetermination based on the latest peak load forecast for the studied period, the same computer \nsimulation model of loads, generation and transmission topography employed in the \ndetermination of Capacity Emergency Transfer Limit for such Delivery Year, including external \nfacilities from an industry standard model of the loads, generation, and transmission topography \nof the Eastern Interconnection under peak conditions.  PJM shall specify in the PJM Manuals the \nareas and minimum distribution factors for identifying monitored bulk electric system facilities \nthat have an electrically significant response to such transfers on the PJM interface.  Employing \nsuch tools, PJM shall model increased power transfers from external areas into PJM to determine \nthe transfer level at which one or more reliability criteria is violated on any monitored bulk \nelectric system facilities that have an electrically significant response to such transfers.  For the \nPJM Region Capacity Import Limit, PJM shall optimize transfers from other source areas not \nexperiencing any reliability criteria violations as appropriate to increase the Capacity Import \nLimit.  The aggregate megawatt quantity of transfers into PJM at the point where any increase in \ntransfers on the interface would violate reliability criteria will establish the Capacity Import \nLimit.  Notwithstanding the foregoing, a Capacity Resource located outside the PJM Region \nshall not be subject to the Capacity Import Limit if the Capacity Market Seller seeks an \nexception thereto by demonstrating to PJM, by no later than five (5) business days prior to the \ncommencement of the offer period for the relevant RPM Auction, that such resource meets all of \nthe following requirements: \n(i)  \nit has, at the time such exception is requested, met all applicable requirements to \nbe pseudo-tied into the PJM Region, or the Capacity Market Seller has committed in writing that \nit will meet such requirements, unless prevented from doing so by circumstances beyond the \ncontrol of the Capacity Market Seller, prior to the relevant Delivery Year; \n \n(ii)  \nat the time such exception is requested, it has long-term firm transmission service \nconfirmed on the complete transmission path from such resource into PJM; and \n \n(iii) \nit is, by written commitment of the Capacity Market Seller, subject to the same \nobligations imposed on Generation Capacity Resources located in the PJM Region by Tariff, \nAttachment DD, section 6.6 to offer their capacity into RPM Auctions; provided, however, that \n(a) the total megawatt quantity of all exceptions granted hereunder for a Delivery Year, plus the \nCapacity Import Limit for the applicable interface determined for such Delivery Year, may not \nexceed the total megawatt quantity of Network External Designated Transmission Service on"},{"page":110,"startToken":37696,"endToken":38132,"text":"such interface that PJM has confirmed for such Delivery Year; and (b) if granting a qualified \nexception would result in a violation of the rule in clause (a), PJM shall grant the requested \nexception but reduce the Capacity Import Limit by the quantity necessary to ensure that the total \nquantity of Network External Designated Transmission Service is not exceeded. \n \nCapacity Only Option: \n \n“Capacity Only Option” shall mean participation in Emergency Load Response Program or Pre-\nEmergency Program which allows, pursuant to Tariff, Attachment DD and as applicable, a \ncapacity payment for the ability to reduce load during a pre-emergency or emergency event. \n \nCapacity Performance Resource: \n \n“Capacity Performance Resource” shall have the same meaning as in Tariff, Attachment DD. \n \nCapacity Resources: \n \n \n“Capacity Resources” shall mean megawatts of (i) net capacity from Existing Generation \nCapacity Resources or Planned Generation Capacity Resources meeting the requirements of the \nReliability Assurance Agreement, Schedules 9 and Reliability Assurance Agreement, Schedule \n10 that are or will be owned by or contracted to a Party and that are or will be committed to \nsatisfy that Party's obligations under the Reliability Assurance Agreement, or to satisfy the \nreliability requirements of the PJM Region, for a Delivery Year; (ii) net capacity from Existing \nGeneration Capacity Resources or Planned Generation Capacity Resources not owned or \ncontracted for by a Party which are accredited to the PJM Region pursuant to the procedures set \nforth in such Schedules 9 and 10; or (iii)  load reduction capability provided by Demand \nResources or Energy Efficiency Resources that are accredited to the PJM Region pursuant to the \nprocedures set forth in the Reliability Assurance Agreement, Schedule 6; or (iv) generation and \nload reduction capability provided by a DER Capacity Aggregation Resource, pursuant to the \nprocedures set forth in the Reliability Assurance Agreement, Schedule 6.2 and the PJM Manuals. \n \n \nCapacity Resource Provider: \n \n“Capacity Resource Provider” shall mean a Member that (1) owns, or has the contractual \nauthority to control the output of, a Generation Capacity Resource, that has not transferred such \nauthority to another entity; (2) or a DER Aggregator that has a contractual relationship to use a \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource. \n \nCapacity Storage Resource Class: \n \n“Capacity Storage Resource Class” shall mean the ELCC Classes specified in Schedules 9.1 and \n9.2, section B of this Agreement, each of which is composed of (1) Capacity Storage Resources \nwith the same specified characteristic duration of 4, 6, 8, and 10 hours or; (2) storage device \nComponent DER. The characteristic duration of an Energy Storage Resource Class is the ratio of"},{"page":111,"startToken":38132,"endToken":38442,"text":"the modeled MWh energy storage capability of members of the class to the modeled MW power \ncapability of members of the class. \n \nCapacity Transfer Right: \n \n \n“Capacity Transfer Right” shall have the meaning specified in Tariff, Attachment DD. \n \nCoal Class: \n \n \n“Coal Class” shall mean an ELCC Class consisting of Unlimited Resources primarily \nfueled by coal. \n \nCombination Resource: \n \n“Combination Resource” shall mean a Generation Capacity Resource, or a generation \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource, that has a component that has the characteristics of a Limited Duration \nResource combined with (i) a component that has the characteristics of an Unlimited Resource or \n(ii) a component that has the characteristics of a Variable Resource. \n \nCompliance Aggregation Area (CAA): \n \n“Compliance Aggregation Area” or “CAA” shall have the same meaning as in the Tariff. \n \nComplex Hybrid Class: \n \n“Complex Hybrid Class” shall mean an ELCC Class composed of Combination Resources that \ncombine three or more components, whereby one component is a class of Limited Duration \nResource, and the other components are different Variable Resource classes, and such \nCombination Resources cannot be included in any other Combination Resource class. A resource \nthat is a member of a Complex Hybrid Class has a single Point Of Interconnection, unless the \nresource is controlled in an integrated fashion, is at a single site, and is approved by PJM to be \nconsidered a single resource in accordance with the PJM Manuals. \n \nConsolidated Transmission Owners Agreement, PJM Transmission Owners Agreement or \nTransmission Owners Agreement: \n \n \n“Consolidated Transmission Owners Agreement,” “PJM Transmission Owners Agreement” or \n“Transmission Owners Agreement” shall mean that certain Consolidated Transmission Owners \nAgreement, dated as of December 15, 2005, by and among the Transmission Owners and by and \nbetween the Transmission Owners and PJM Interconnection, L.L.C. on file with the \nCommission, as amended from time to time. \n \n \nControl Area:"},{"page":112,"startToken":38442,"endToken":38748,"text":"“Control Area” shall mean an electric power system or combination of electric power systems \nbounded by interconnection metering and telemetry to which a common generation control \nscheme is applied in order to: \n \n \n \n(a) \nmatch the power output of the generators within the electric power system(s) and \nenergy purchased from entities outside the electric power system(s), with the load within the \nelectric power system(s); \n \n \n \n(b) \nmaintain scheduled interchange with other Control Areas, within the limits of \nGood Utility Practice; \n \n \n \n (c) \nmaintain the frequency of the electric power system(s) within reasonable limits in \naccordance with Good Utility Practice and the criteria of NERC and each Applicable Regional \nEntity; \n \n \n \n(d) \nmaintain power flows on transmission facilities within appropriate limits to \npreserve reliability; and \n \n \n \n(e) \nprovide sufficient generating capacity to maintain operating reserves in \naccordance with Good Utility Practice. \n \n \nDaily Unforced Capacity Obligation: \n \n \n“Daily Unforced Capacity Obligation” shall mean the capacity obligation of a Load Serving \nEntity during the Delivery Year, determined in accordance with the Reliability Assurance \nAgreement, Schedule 8 or, as to an FRR Entity, in the Reliability Assurance Agreement, \nSchedule 8.1. \n \n \nDelivery Year: \n \n \n“Delivery Year” shall mean a Planning Period for which a Capacity Resource is committed \npursuant to the auction procedures specified in Tariff, Attachment DD or pursuant to an FRR \nCapacity Plan under RAA, Schedule 8.1. \n \n \nDemand Resource (DR): \n \n \n“Demand Resource” or “DR” shall mean a Limited Demand Resource, Extended Summer \nDemand Resource, Annual Demand Resource, Base Capacity Demand Resource or Summer-\nPeriod Demand Resource with a demonstrated capability to provide a reduction in demand or \notherwise control load in accordance with the requirements of RAA, Schedule 6 that offers and \nthat clears load reduction capability in a Base Residual Auction or Incremental Auction or that is \ncommitted through an FRR Capacity Plan.   \n \nDemand Resource Factor or DR Factor:"},{"page":113,"startToken":38748,"endToken":39063,"text":"“Demand Resource Factor” or “DR Factor” shall mean, for Delivery Years through May 31, \n2018, that factor approved from time to time by the PJM Board used to determine the unforced \ncapacity value of a Demand Resource in accordance with Reliability Assurance Agreement, \nSchedule 6 \n \nDemand Resource Officer Certification Form: \n \n“Demand Resource Officer Certification Form” shall mean a certification as to an intended \nDemand Resource Sell Offer, in accordance with Reliability Assurance Agreement, Schedule 6 \nand Reliability Assurance Agreement, Schedule 8.1 and the PJM Manuals. \n \n \nDemand Resource Registration: \n \n“Demand Resource Registration” shall mean a registration in the Full Program Option or \nCapacity Only Option of the Emergency or Pre-Emergency Load Resource Program in \naccordance with Tariff, Attachment K-Appendix, section 8. \n \nDemand Resource Sell Offer Plan: \n \n“Demand Resource Sell Offer Plan” shall mean the plan required by Reliability Assurance \nAgreement, Schedule 6 and Reliability Assurance Agreement, Schedule 8.1 in support of an \nintended offer of Demand Resources in an RPM Auction, or an intended inclusion of Demand \nResources in an FRR Capacity Plan. \n \nDiesel Utility Class: \n \n\"Diesel Utility Class\" shall mean an ELCC Class consisting of Unlimited Resources of the diesel \ntechnology type that is not primarily fueled by landfill gas. \n \nDER Aggregator Officer Certification Form:  \n \n“DER Aggregator Officer Certification Form” shall mean a DER Aggregator’s certification as to \nan intended DER Capacity Aggregation Resource Sell Offer, in accordance with Reliability \nAssurance Agreement, Schedule 6.2 and Reliability Assurance Agreement, Schedule 8.1 and the \nPJM Manuals. \n \nDER Capacity Aggregation Resource Sell Offer Plan:  \n \n“DER Capacity Aggregation Resource Sell Offer Plan” shall mean the plan required by \nReliability Assurance Agreement, Schedule 6.2 and Reliability Assurance Agreement, Schedule \n8.1 in support of an intended offer of a DER Capacity Aggregation Resource in an RPM \nAuction, or an intended inclusion of a DER Capacity Aggregation Resource in an FRR Capacity \nPlan. \n \nEffective Nameplate Capacity:"},{"page":114,"startToken":39063,"endToken":39507,"text":"“Effective Nameplate Capacity” shall mean (i) for each Variable Resource and Combination \nResource that is a Generation Capacity Resource, the resource’s Maximum Facility Output (or, \nfor a Co-Located Resource, the applicable share of the Mixed Technology Facility’s Maximum \nFacility Output); (ii) for each Variable Resource and Combination Resource, that is an individual \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource, the device’s maximum energy production capability, as defined by the \nresource’s state interconnection agreement; or (iii) for each Limited Duration Resource, the \nsustained level of output that the device can provide and maintain over a continuous period, \nwhereby the duration of that continuous period matches the characteristic duration of the \ncorresponding ELCC Class, with consideration given to ambient conditions expected to exist at \nthe time of PJM system peak load, to the extent that such conditions impact such resource’s \ncapability, not to exceed the Maximum Facility Output (or, for a Co-Located Resource, the \napplicable share of the Mixed Technology Facility’s Maximum Facility Output).  For the \n2025/2026 Delivery Year and subsequent Delivery Years, the Effective Nameplate Capacity of \neach Limited Duration Resource shall not exceed the greater of the Capacity Interconnection \nRights of such Limited Duration Resource, or the transitional system capability as limited by the \ntransitional resource MW ceiling as defined in the PJM Manuals, awarded for the applicable \nDelivery Year. \n \nEffective UCAP: \n \n“Effective UCAP” shall mean a unit of measure that represents the capacity product transacted in \nthe Reliability Pricing Model and included in FRR Capacity Plans.  One megawatt of Effective \nUCAP has the same capacity value of one megawatt of Unforced Capacity. \n \nELCC Class: \n \n“ELCC Class” shall mean a defined group of ELCC Resources that share a common set of \noperational characteristics and for which effective load carrying capability analysis, as set forth \nin RAA, Schedules 9.1 and 9.2, will establish a unique ELCC Class UCAP and corresponding \nELCC Class Rating(s). ELCC Classes shall be defined in the Schedules 9.1 and 9.2, section B of \nthis Agreement.  Members of an ELCC Class shall share a common method of calculating the \nELCC Resource Performance Adjustment, provided that the individual ELCC Resource \nPerformance Adjustment values will generally differ among ELCC Resources. \n \nELCC Class Rating: \n \n“ELCC Class Rating” shall mean the rating factor, based on effective load carrying capability \nanalysis, that applies to ELCC Resources that are members of an ELCC Class as part of the \ncalculation of their Accredited UCAP. \n \nELCC Class UCAP: \n \n“ELCC Class UCAP” shall mean the aggregate Effective UCAP all modeled ELCC Resources in \na given ELCC Class are capable of providing in a given Delivery Year."},{"page":115,"startToken":39507,"endToken":39872,"text":"ELCC Portfolio UCAP: \n \n“ELCC Portfolio UCAP” shall mean the aggregate Effective UCAP that all modeled ELCC \nResources are capable of providing in a given Delivery Year. \n \nELCC Resource: \n \n“ELCC Resource” shall mean a Component DER within a DER Aggregation Resource that is \nlinked to a DER Capacity Aggregation Resource, a Generation Capacity Resource or a Demand \nResource. \n \nELCC Resource Performance Adjustment: \n \n“ELCC Resource Performance Adjustment” shall mean the performance of a specific ELCC \nResource relative to the aggregate performance of the ELCC Class to which it belongs as further \ndescribed in RAA, Schedule 9.1, section F and RAA, Schedule 9.2, section D. \n \nElectric Cooperative: \n \n \n“Electric Cooperative” shall mean an entity owned in cooperative form by its customers that is \nengaged in the generation, transmission, and/or distribution of electric energy. \n \n \nElectric Distributor: \n \n \n“Electric Distributor” shall mean a Member that 1) owns or leases with rights equivalent to \nownership of electric distribution facilities that are used to provide electric distribution service to \nelectric load within the PJM Region; or 2) is a generation and transmission cooperative or a joint \nmunicipal agency that has a member that owns electric distribution facilities used to provide \nelectric distribution service to electric load within the PJM Region. \n \n \nEmergency: \n \n \n“Emergency” shall mean (i) an abnormal system condition requiring manual or automatic action \nto maintain system frequency, or to prevent loss of firm load, equipment damage, or tripping of \nsystem elements that could adversely affect the reliability of an electric system or the safety of \npersons or property; or (ii) a fuel shortage requiring departure from normal operating procedures \nin order to minimize the use of such scarce fuel; or (iii) a condition that requires implementation \nof emergency procedures as defined in the PJM Manuals. \n \n \nEnd-Use Customer: \n \n \n“End-Use Customer” shall mean a Member that is a retail end-user of electricity within the PJM \nRegion.  For purposes of Members Committee sector classification, a Member that is a retail \nend-user that owns generation may qualify as an End-Use customer if:  (1) the average physical \nunforced capacity owned by the Member and its affiliates in the PJM region over the five \nPlanning Periods immediately preceding the relevant Planning Period does not exceed the"},{"page":116,"startToken":39872,"endToken":40311,"text":"average PJM capacity obligation for the Member and its affiliates over the same time period; or \n(2) the average energy produced by the Member and its affiliates within the PJM region over the \nfive Planning Periods immediately preceding the relevant Planning Period does not exceed the \naverage energy consumed by that Member and its affiliates within the PJM region over the same \ntime period.  The foregoing notwithstanding, taking retail service may not be sufficient to qualify \na Member as an End-Use Customer. \n \n \n \nEnergy Efficiency Resource: \n \n \n“Energy Efficiency Resource” shall mean a project, including installation of more efficient \ndevices or equipment or implementation of more efficient processes or systems, meeting the \nrequirements of RAA, Schedule 6 and exceeding then-current building codes, appliance \nstandards, or other relevant standards, designed to achieve a continuous (during the periods \ndescribed in Reliability Assurance Agreement, Schedule 6 and the PJM Manuals) reduction in \nelectric energy consumption that is not reflected in the peak load forecast prepared for the \nDelivery Year for which the Energy Efficiency Resource is proposed, and that is fully \nimplemented at all times during such Delivery Year, without any requirement of notice, dispatch, \nor operator intervention.  Annual Energy Efficiency Resources, Base Capacity Energy Efficiency \nResources and Summer-Period Energy Efficiency Resources are types of Energy Efficiency \nResources. \n \nExigent Water Storage: \n \n“Exigent Water Storage” shall mean water stored in the pondage or reservoir of a hydropower \nresource which is not typically available during normal operating conditions (as those conditions \nare described in the relevant FERC hydropower license), but which can be drawn upon during \nemergency conditions (as described in the FERC hydropower license), including in order to \navoid a load shed.  In an effective load carrying capability analysis, exigent storage capability \nfrom an upstream hydro facility can be considered relative to a downstream hydro facility by \nassessing cascading storage and flows. \n \nExisting Demand Resource: \n \n“Existing Demand Resource” shall mean a Demand Resource for which the Demand Resource \nProvider has identified existing end-use customer sites that are registered for the current Delivery \nYear with PJM (even if not registered by such Demand Resource Provider) and that the Demand \nResource Provider reasonably expects to have under a contract to reduce load based on PJM \ndispatch instructions by the start of the Delivery Year for which such resource is offered. \n \nExisting DER Capacity Aggregation Resource: \n \n“Existing DER Capacity Aggregation Resource” shall mean a DER Capacity Aggregation \nResource for which the DER Aggregator has identified existing Component DER that are \nregistered in a DER Capacity Aggregation Resource for the current Delivery Year with PJM \n(even if not registered by such DER Aggregator) and that the DER Aggregator reasonably"},{"page":117,"startToken":40311,"endToken":40743,"text":"expects to have under a contract to generate or reduce load based on PJM dispatch instructions \nby the start of the Delivery Year for which such DER Capacity Aggregation Resource is offered. \n \nExisting Generation Capacity Resource: \n \n“Existing Generation Capacity Resource” shall mean, for purposes of the must-offer requirement \nand mitigation of offers for any RPM Auction for a Delivery Year, a Generation Capacity \nResource that, as of the date on which bidding commences for such auction: (a) is in service; or \n(b) is not yet in service, but has cleared any RPM Auction for any prior Delivery Year.  A \nGeneration Capacity Resource shall be deemed to be in service if interconnection service has \never commenced (for resources located in the PJM Region), or if it is physically and electrically \ninterconnected to an external Control Area and is in full commercial operation (for resources not \nlocated in the PJM Region).  The additional megawatts of a Generation Capacity Resource that is \nbeing, or has been, modified to increase the number of megawatts of available installed capacity \nthereof shall not be deemed to be an Existing Generation Capacity Resource until such time as \nthose megawatts (a) are in service; or (b) are not yet in service, but have cleared any RPM \nAuction for any prior Delivery Year. \n \nExtended Summer Demand Resource: \n \n“Extended Summer Demand Resource” shall mean, for Delivery Years through May 31, 2018, \nand for FRR Capacity Plans Delivery Years through May 31, 2019, a resource that is placed \nunder the direction of the Office of the Interconnection and that will be available June through \nOctober and the following May, and will be available for an unlimited number of interruptions \nduring such months by the Office of the Interconnection, and will be capable of maintaining each \nsuch interruption for at least a 10-hour duration between the hours of 10:00AM to 10:00PM \nEastern Prevailing Time. The Extended Summer Demand Resource must be available June \nthrough October and the following May in the corresponding Delivery Year to be offered for sale \nor Self-Supplied in an RPM Auction, or included as an Extended Summer Demand Resource in \nan FRR Capacity Plan for the corresponding Delivery Year.   \n \n \nFacilities Study Agreement: \n \n \n“Facilities Study Agreement” shall have the same meaning as in Tariff, Part VI, section 206. \n \n \n \nFERC or Commission: \n \n \n“FERC” or “Commission” shall mean the Federal Energy Regulatory Commission or any \nsuccessor federal agency, commission or department exercising jurisdiction over the Tariff, \nOperating Agreement and Reliability Assurance Agreement. \n \n \nFirm Point-To-Point Transmission Service: \n \n \n“Firm Point-To-Point Transmission Service” shall have the meaning specified in the Tariff. \n \n \nFirm Service Level:"},{"page":118,"startToken":40743,"endToken":41083,"text":"“Firm Service Level” or “FSL” of Price Responsive Demand shall mean the level, determined at \na PRD Substation level, to which Price Responsive Demand shall be reduced during the Delivery \nYear when the Locational Marginal Price exceeds the price associated with such Price \nResponsive Demand identified by the PRD Provider in its PRD Plan. “Firm Service Level” or \n“FSL” of Demand Resource shall mean the pre-determined level to which an end-use customer’s \nload shall be reduced, upon notification from the Curtailment Service Provider’s market \noperations center or its agent. \n \nFirm Transmission Service: \n \n \n“Firm Transmission Service” shall mean transmission service that is intended to be available at \nall times to the maximum extent practicable, subject to an Emergency, an unanticipated failure of \na facility, or other event beyond the control of the owner or operator of the facility or the Office \nof the Interconnection. \n \n \nFixed Resource Requirement Alternative or FRR Alternative: \n \n \n“Fixed Resource Requirement Alternative” or “FRR Alternative” shall mean an alternative \nmethod for a Party to satisfy its obligation to provide Unforced Capacity hereunder, as set forth \nin the Reliability Assurance Agreement, Schedule 8.1. \n \nFixed-Tilt Solar Class: \n \n“Fixed-Tilt Solar Class” shall mean an ELCC Class consisting of Variable Resources that \nproduce electrical energy with solar panels that are primarily mounted in a fixed orientation. \n \n \nForecast Pool Requirement: \n \n \n“Forecast Pool Requirement” or “FPR” shall mean the amount equal to one plus the unforced \nreserve margin (stated as a decimal number) for the PJM Region required pursuant to this \nReliability Assurance Agreement, as approved by the PJM Board pursuant to Reliability \nAssurance Agreement, Schedule 4.1. \n \n \nFRR Capacity Plan or FRR Plan: \n \n \n“FRR Capacity Plan” or “FRR Plan” shall mean a long-term plan for the commitment of \nCapacity Resources and Price Responsive Demand to satisfy the capacity obligations of a Party \nthat has elected the FRR Alternative, as more fully set forth in the Reliability Assurance \nAgreement, Schedule 8.1. \n \n \nFRR Entity: \n \n \n“FRR Entity” shall mean, for the duration of such election, a Party that has elected the FRR \nAlternative hereunder."},{"page":119,"startToken":41083,"endToken":41545,"text":"FRR Service Area: \n \n \n“FRR Service Area” shall mean (a) the service territory of an IOU as recognized by state law, \nrule or order; (b) the service area of a Public Power Entity or Electric Cooperative as recognized \nby franchise or other state law, rule, or order; or (c) a separately identifiable geographic area that \nis: (i) bounded by wholesale metering, or similar appropriate multi-site aggregate metering, that \nis visible to, and regularly reported to, the Office of the Interconnection, or that is visible to, and \nregularly reported to an Electric Distributor and such Electric Distributor agrees to aggregate the \nload data from such meters for such FRR Service Area and regularly report such aggregated \ninformation, by FRR Service Area, to the Office of the Interconnection; and (ii) for which the \nFRR Entity has or assumes the obligation to provide capacity for all load (including load growth) \nwithin such area.  In the event that the service obligations of an Electric Cooperative or Public \nPower Entity are not defined by geographic boundaries but by physical connections to a defined \nset of customers, the FRR Service Area in such circumstances shall be defined as all customers \nphysically connected to transmission or distribution facilities of such Electric Cooperative or \nPublic Power Entity within an area bounded by appropriate wholesale aggregate metering as \ndescribed above.   \n \n \nFull Program Option: \n \n“Full Program Option” shall mean participation in Emergency Load Response Program or Pre-\nEmergency Program which allows, pursuant to Tariff, Attachment DD and as applicable, (i) an \nenergy payment for load reductions during a pre-emergency or emergency event, and (ii) a \ncapacity payment for the ability to reduce load during a pre-emergency or emergency event. \n \nFull Requirements Service: \n \n \n“Full Requirements Service” shall mean wholesale service to supply all of the power needs of a \nLoad Serving Entity to serve end-users within the PJM Region that are not satisfied by its own \ngenerating facilities. \n \nGas Combined Cycle Class: \n \n“Gas Combined Cycle Class” shall mean an ELCC Class consisting of Unlimited Resources of \nthe combined cycle technology type that is primarily fueled by natural gas, but does not meet the \nrequirements to be included in the Gas Combined Cycle Dual Fuel Class. \n \nGas Combined Cycle Dual Fuel Class: \n \n“Gas Combined Cycle Dual Fuel Class” shall mean an ELCC Class consisting of Unlimited \nResources of the combined cycle technology type that is primarily fueled by natural gas, and that \nattests that it has the capability to start independently using onsite sources and operate \nindependently on alternate onsite fuel source(s) up to its maximum capacity level during the \nwinter season of the applicable Delivery Year in which it is providing capacity, and capable of \noperating on the alternate fuel for two 16-hour periods over two consecutive days at its \nmaximum capacity level."},{"page":120,"startToken":41545,"endToken":41995,"text":"Gas Combustion Turbine Class: \n \n“Gas Combustion Turbine Class” shall mean an ELCC Class consisting of Unlimited Resources \nof the combustion turbine technology type that is primarily fueled by natural gas, but does not \nmeet the requirements to be included in the Gas Combustion Turbine Dual Fuel Class. \n \nGas Combustion Turbine Dual Fuel Class: \n \n“Gas Combustion Turbine Dual Fuel Class” shall mean an ELCC Class consisting of Unlimited \nResources of the combustion turbine technology type that is primarily fueled by natural gas, and \nattests that it has the capability to start independently using onsite sources and operate \nindependently on alternate onsite fuel source(s) up to its maximum capacity level during the \nwinter season of the applicable Delivery Year in which it is providing capacity, and capable of \noperating on the alternate fuel for two 16-hour periods over two consecutive days at its \nmaximum capacity level. \n \n \nGeneration Capacity Resource: \n \n \n“Generation Capacity Resource” shall mean a Generating Facility, or the contractual right to \ncapacity from a specified Generating Facility, that meets the requirements of RAA, Schedule 9 \nand RAA, Schedule 10, and, for Generating Facilities that are committed to an FRR Capacity \nPlan, that meets the requirements of RAA, Schedule 8.1.  A Generation Capacity Resource may \nbe an Existing Generation Capacity Resource or a Planned Generation Capacity Resource.  \n \nGeneration Owner: \n \n \n“Generation Owner” shall mean a Member that owns or leases with rights equivalent to \nownership, or otherwise controls and operates one or more operating generation resources \nlocated in the PJM Region.  The foregoing notwithstanding, for a planned generation resource to \nqualify a Member as a Generation Owner, such resource shall have cleared an RPM auction, and \nfor Energy Resources, the resource shall have a FERC-jurisdictional interconnection agreement \nor wholesale market participation agreement within PJM.   Purchasing all or a portion of the \noutput of a generation resource shall not be sufficient to qualify a Member as a Generation \nOwner.  For purposes of Members Committee sector classification, a Member that is primarily a \nretail end-user of electricity that owns generation may qualify as a Generation Owner if:  (1) the \ngeneration resource is the subject of a FERC-jurisdictional interconnection agreement or \nwholesale market participation agreement within PJM; (2) the average physical unforced \ncapacity owned by the Member and its affiliates over the five Planning Periods immediately \npreceding the relevant Planning Period exceeds the average PJM capacity obligation of the \nMember and its affiliates over the same time period; and (3) the average energy produced by the \nMember and its affiliates within PJM over the five Planning Periods immediately preceding the \nrelevant Planning Period exceeds the average energy consumed by the Member and its affiliates \nwithin PJM over the same time period. \n \n \nGenerator Forced Outage:"},{"page":121,"startToken":41995,"endToken":42446,"text":"“Generator Forced Outage” shall mean an immediate reduction in output or capacity or removal \nfrom service, in whole or in part, of a generating unit by reason of an Emergency or threatened \nEmergency, unanticipated failure, or other cause beyond the control of the owner or operator of \nthe facility, as specified in the relevant portions of the PJM Manuals.  A reduction in output or \nremoval from service of a generating unit in response to changes in market conditions shall not \nconstitute a Generator Forced Outage. \n \n \nGenerator Maintenance Outage: \n \n \n“Generator Maintenance Outage” shall mean the scheduled removal from service, in whole or in \npart, of a generating unit in order to perform repairs on specific components of the facility, if \nremoval of the facility qualifies as a maintenance outage pursuant to the PJM Manuals. \n \n \nGenerator Planned Outage: \n \n \n“Generator Planned Outage” shall mean the scheduled removal from service, in whole or in part, \nof a generating unit for inspection, maintenance or repair with the approval of the Office of the \nInterconnection in accordance with the PJM Manuals. \n \n \nGood Utility Practice: \n \n \n“Good Utility Practice” shall mean any of the practices, methods and acts engaged in or \napproved by a significant portion of the electric utility industry during the relevant time period, \nor any of the practices, methods and acts which, in the exercise of reasonable judgment in light \nof the facts known at the time the decision was made, could have been expected to accomplish \nthe desired result at a reasonable cost consistent with good business practices, reliability, safety \nand expedition.  Good Utility Practice is not intended to be limited to the optimum practice, \nmethod, or act to the exclusion of all others, but rather is intended to include acceptable \npractices, methods, or acts generally accepted in the region; including those practices required by \nFederal Power Act Section 215(a)(4).  \n \n \nHybrid Resource Class: \n \n“Hybrid Resource Class” shall mean the ELCC Classes specified in RAA Schedules 9.1 and 9.2 \nSection B.  Each Hybrid Resource Class has a specified combination of two components, \nwhereby, absent being part of a Combination Resource, the individual components would be in a \nCapacity Storage Resource Class, a Variable Resource Class or would be an Unlimited \nResource.  A resource that is a member of a Hybrid Resource Class has a single Point Of \nInterconnection, unless the resource is controlled in an integrated fashion, is at a single site, and \nis approved by PJM to be considered a single resource in accordance with the PJM Manuals. \n \nHydropower With Non-Pumped Storage: \n \n“Hydropower With Non-Pumped Storage” shall mean a hydropower facility that can capture and \nstore incoming stream flow, without use of pumps, in pondage or a reservoir, and the Generation"},{"page":122,"startToken":42446,"endToken":42802,"text":"Owner has the ability, within the constraints available in the applicable operating license, to exert \nmaterial control over the quantity of stored water and output of the facility throughout an \nOperating Day. \n \nHydropower With Non-Pumped Storage Class: \n \n“Hydropower With Non-Pumped Storage Class” shall mean an ELCC Class consisting of \nCombination Resources that are Hydropower With Non-Pumped Storage resources. \n \nIncremental Auction: \n \n \n“Incremental Auction” shall mean any of several auctions conducted for a Delivery Year after \nthe Base Residual Auction for such Delivery Year and before the first day of such Delivery Year, \nincluding the First Incremental Auction, Second Incremental Auction, Third Incremental \nAuction, or Conditional Incremental Auction.  Incremental Auctions (other than the Conditional \nIncremental Auction), shall be held for the purposes of: \n \n(i) \nallowing Market Sellers that committed Capacity Resources in the Base Residual \nAuction for a Delivery Year, which subsequently are determined to be unavailable \nto deliver the committed Unforced Capacity in such Delivery Year (due to \nresource retirement, resource cancellation or construction delay, resource \nderating, EFORd increase, Accredited UCAP Factor decrease, a decrease in the \nNominated Demand Resource Value of a Planned Demand Resource, delay or \ncancellation of a Qualifying Transmission Upgrade, or similar occurrences) to \nsubmit Buy Bids for replacement Capacity Resources; and  \n \n(ii) \nallowing the Office of the Interconnection to reduce or increase the amount of \ncommitted capacity secured in prior auctions for such Delivery Year if, as a result \nof changed circumstances or expectations since the prior auction(s), there is, \nrespectively, a significant excess or significant deficit of committed capacity for \nsuch Delivery Year, for the PJM Region or for an LDA. \n \n \nIntermittent Hydropower Class: \n \n“Intermittent Hydropower Class” shall mean an ELCC Class consisting of Variable Resources \nthat are run-of-river hydropower generators that must generally pass incoming water and \ntherefore cannot appreciably store water to later increase the output of the facility. Resources in \nthe Intermittent Hydropower Class are not Hydropower with Non-Pumped Storage resources. \n \nIOU: \n \n \n“IOU” shall mean an investor-owned utility with substantial business interest in owning and/or \noperating electric facilities in any two or more of the following three asset categories:  \ngeneration, transmission, distribution. \n \nIntermittent Landfill Gas Class:"},{"page":123,"startToken":42802,"endToken":43241,"text":"“Intermittent Landfill Gas Class” shall mean an ELCC Class consisting of Variable Resources \nfueled by landfill gas that, because of fuel availability patterns, cannot run consistently at \ninstalled capacity levels for 24 or more hours. \n \nLarge Load: \n \n“Large Load” shall mean end-use customer(s) load that has a cumulative peak load of 50 \nmegawatts or greater at a single electrical site behind one or more points of interconnection, \nwhere for configurations involving multiple affiliated load facilities or multiple points of \ninterconnection with affiliated load facilities behind them, all affiliated load facilities within a \none-mile radius will be considered a single electrical site as further described in the PJM \nManuals. \n \nLarge Load Adjustment: \n \n“Large Load Adjustment” shall mean any MW quantity of adjustments to summer peak load at \nthe “zone/area” level and summed by Zone as further detailed in PJM Manuals.  For purposes of \nthis definition, a “zone/area” is an area within a Zone for which the relevant Electric Distributor \nspecifies a separate Obligation Peak Load MW value.  A zone/area is a service area of an \nElectric Distributor that is a separately identifiable, geographic area bounded by wholesale \nmetering (e.g., the service territory of an operating company of a Transmission Owner). \n \nLimited Demand Resource: \n \n \n“Limited Demand Resource” shall mean, for Delivery Years through May 31, 2018, and for FRR \nCapacity Plans Delivery Years through May 31, 2019, a resource that is placed under the \ndirection of the Office of the Interconnection and that will, at a minimum, be available for \ninterruption for at least 10 Load Management Events during the summer period of June through \nSeptember in the Delivery Year, and will be capable of maintaining each such interruption for at \nleast a 6-hour duration.  At a minimum, the Limited Demand Resource shall be available for \nsuch interruptions on weekdays, other than NERC holidays, from 12:00PM (noon) to 8:00PM \nEastern Prevailing Time.  The Limited Demand Resource must be available during the summer \nperiod of June through September in the corresponding Delivery Year to be offered for sale or \nSelf-Supplied in an RPM Auction, or included as a Limited Demand Resource in an FRR \nCapacity Plan for the corresponding Delivery Year. \n \nLimited Duration Resource: \n \n“Limited Duration Resource” shall mean a Generation Capacity Resource or a generation \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource, that is not a Variable Resource, that is not a Combination Resource, and \nthat is not capable of running continuously at Maximum Facility Output for 24 hours or longer.  \nA Capacity Storage Resource is a Limited Duration Resource. \n \n \nLoad Serving Entity or LSE:"},{"page":124,"startToken":43241,"endToken":43539,"text":"“Load Serving Entity” or “LSE” shall mean any entity (or the duly designated agent of such an \nentity), including a load aggregator or power marketer, (i) serving end-users within the PJM \nRegion, and (ii) that has been granted the authority or has an obligation pursuant to state or local \nlaw, regulation or franchise to sell electric energy to end-users located within the PJM Region.  \nLoad Serving Entity shall include any end-use customer that qualifies under state rules or a \nutility retail tariff to manage directly its own supply of electric power and energy and use of \ntransmission and ancillary services. \n \n \nLocational Reliability Charge: \n \n \n“Locational Reliability Charge” shall mean the charge determined pursuant to RAA, Article 7, \nsection 2. \n \n \nMarkets and Reliability Committee: \n \n \n“Markets and Reliability Committee” shall mean the committee established pursuant to the \nOperating Agreement as a Standing Committee of the Members Committee.  \n \n \nMaximum Emergency Service Level: \n \n“Maximum Emergency Service Level” or “MESL” of Price Responsive Demand for the \n2017/2018 through the 2021/2022 Delivery Years shall mean the level, determined at a PRD \nSubstation level, to which Price Responsive Demand shall be reduced during the Delivery Year \nwhen a Maximum Generation Emergency is declared and the Locational Marginal Price exceeds \nthe price associated with such Price Responsive Demand identified by the PRD Provider in its \nPRD Plan. \n \nMember: \n \n \n“Member” shall have the meaning provided in the Operating Agreement. \n \n \nMembers Committee: \n \n \n“Members Committee” shall mean the committee specified in Operating Agreement, section 8 \ncomposed of the representatives of all the Members. \n \n \nNERC: \n \n \n“NERC” shall mean the North American Electric Reliability Corporation or any successor \nthereto. \n \nNetwork External Designated Transmission Service: \n \n“Network External Designated Transmission Service” shall mean the quantity of network \ntransmission service confirmed by PJM for use by a market participant to import power and"},{"page":125,"startToken":43539,"endToken":43813,"text":"energy from an identified Generation Capacity Resource located outside the PJM Region, upon \ndemonstration by such market participant that it owns such Generation Capacity Resource, has \nan executed contract to purchase power and energy from such Generation Capacity Resource, or \nhas a contract to purchase power and energy from such Generation Capacity Resource contingent \nupon securing firm transmission service from such resource. \n \nNetwork Resources: \n \n \n“Network Resources” shall have the meaning set forth in the PJM Tariff. \n \n \nNetwork Transmission Service: \n \n \n“Network Transmission Service” shall mean transmission service provided pursuant to the rates, \nterms and conditions set forth in Tariff, Part III or transmission service comparable to such \nservice that is provided to a Load Serving Entity that is also a Transmission Owner. \n \nNominal PRD Value:  \n \n“Nominal PRD Value” shall mean, as to any PRD Provider, an adjustment, determined in \naccordance with Reliability Assurance Agreement, Schedule 6.1, to the peak-load forecast used \nto determine the quantity of capacity sought through an RPM Auction, reflecting the aggregate \neffect of Price Responsive Demand on peak load resulting from the Price Responsive Demand to \nbe provided by such PRD Provider.    \n \nNominated Demand Resource Value: \n \n \n“Nominated Demand Resource Value” shall have the meaning specified in Tariff, Attachment \nDD. \n \n \nNon-Retail Behind the Meter Generation: \n \n \n“Non-Retail Behind the Meter Generation” shall mean Behind the Meter Generation that is used \nby municipal electric systems, electric cooperatives, and electric distribution companies to serve \nload. \n \n \nNuclear Class: \n \n“Nuclear Class” shall mean an ELCC Class consisting of Unlimited Resources primarily fueled \nby nuclear fuel. \n \nObligation Peak Load: \n \n \n“Obligation Peak Load” shall have the meaning specified in Reliability Assurance Agreement, \nSchedule 8. \n \n \nOffice of the Interconnection:"},{"page":126,"startToken":43813,"endToken":44124,"text":"“Office of the Interconnection” shall mean the employees and agents of PJM Interconnection, \nL.L.C., subject to the supervision and oversight of the PJM Board, acting pursuant to the \nOperating Agreement. \n \nOffshore Wind Class: \n \n“Offshore Wind Class” shall mean an ELCC Class consisting of Variable Resources that produce \nelectrical energy with offshore wind turbines located in the ocean. \n \nOnshore Wind Class: \n \n“Onshore Wind Class” shall mean an ELCC Class consisting of Variable Resources that produce \nelectrical energy using wind turbines and that are not in the Offshore Wind Class. \n \n \nOperating Agreement of the PJM Interconnection, L.L.C., Operating Agreement or PJM \nOperating Agreement: \n \n \n“Operating Agreement of the PJM Interconnection, L.L.C.,”  “Operating Agreement” or “PJM \nOperating Agreement” shall mean that agreement, dated as of April 1, 1997 and as amended and \nrestated as of June 2, 1997, including all Schedules, Exhibits, Appendices, addenda or \nsupplements hereto, as amended from time to time thereafter, among the Members of the PJM \nInterconnection, L.L.C, on file with the Commission. \n \n \nOperating Day: \n \n“Operating Day” shall have the same meaning as provided in the Operating Agreement. \n \n \nOperating Reserve: \n \n \n“Operating Reserve” shall mean the amount of generating capacity scheduled to be available for \na specified period of an Operating Day to ensure the reliable operation of the PJM Region, as \nspecified in the PJM Manuals. \n \nOrdinary Water Storage: \n \n“Ordinary Water Storage” shall mean water stored in the pondage or reservoir of a hydropower \nresource which is typically available during normal operating conditions pursuant to the FERC \nlicense governing the operation of the hydropower resource. \n \n \nOther Limited Duration Class: \n \n“Other Limited Duration Class” shall mean the ELCC Classes specified in RAA Schedules 9.1 \nand 9.2 section B of this Agreement, each of which has a specified characteristic duration and \nconsists of Limited Duration Resources that are not Capacity Storage Resources. The"},{"page":127,"startToken":44124,"endToken":44539,"text":"characteristic duration of an Other Limited Duration Class is the maximum period of time \nrepresented in the ELCC model that the resources of the class can run at a stated capability. \n \nOther Limited Duration Combination Class: \n \n“Other Limited Duration Combination Class” shall mean the ELCC Classes specified in RAA \nSchedules 9.1 and 9.2 section B. Each Other Limited Duration Class has a specified combination \nof two components, whereby, absent being part of a Combination Resource, one component \nwould be in an Other Limited Duration Class, and the other component would be in a Variable \nResource Class or would be an Unlimited Resource. A resource that is a member of an Other \nLimited Duration Combination Class has a single Point Of Interconnection, unless the resource is \ncontrolled in an integrated fashion, is at a single site, and is approved by PJM to be considered a \nsingle resource in accordance with the PJM Manuals. \n \nOther Supplier: \n \n \n“Other Supplier” shall mean a Member that: (i) is engaged in buying, selling or transmitting \nelectric energy, capacity, ancillary services, Financial Transmission Rights or other services \navailable under PJM’s governing documents in or through the Interconnection or has a good faith \nintent to do so, and (ii) is not a Generation Owner, Electric Distributor, Transmission Owner or \nEnd-Use Customer. \n \n \nOther Unlimited Resource Class: \n \n“Other Unlimited Resource Class” shall mean an ELCC Class consisting of Unlimited Resources \nthat do not qualify for any other ELCC Class specified in RAA Schedule 9.2, section D. \n \nOther Variable Resource Class: \n \n“Other Variable Resource Class” shall mean an ELCC Class consisting of Variable Resources \nthat are not in any other Variable Resource class, including Variable Resources that are \ncomposed of multiple components, each of which would be a Variable Resource. A resource \ncomposed of both fixed-tilt solar panels and tracking solar panels is not in this class. A resource \nthat is a member of a Other Variable Resource Class has a single Point Of Interconnection, \nunless the resource is controlled in an integrated fashion, is at a single site, and is approved by \nPJM to be considered a single resource in accordance with the PJM Manuals. \n \nPartial Requirements Service: \n \n \n“Partial Requirements Service” shall mean wholesale service to supply a specified portion, but \nnot all, of the power needs of a Load Serving Entity to serve end-users within the PJM Region \nthat are not satisfied by its own generating facilities. \n \nParty: \n \n“Party” shall mean an entity bound by the terms of the Operating Agreement."},{"page":128,"startToken":44539,"endToken":44814,"text":"Peak Shaving Adjustment:  \n \n“Peak Shaving Adjustment” shall mean a load forecast mechanism that allows load reductions by \nend-use customers to result in a downward adjustment of the summer load forecast for the \nassociated Zone. Any End-Use Customer identified in an approved peak shaving plan shall not \nalso participate in PJM Markets as Price Responsive Demand, Demand Resource, Base Capacity \nDemand Resource, Capacity Performance Demand Resource, or Economic Load Response \nParticipant. \n \nPercentage Internal Resources Required: \n \n \n“Percentage Internal Resources Required” shall mean, for purposes of an FRR Capacity Plan, the \npercentage of the LDA Reliability Requirement for an LDA that must be satisfied with Capacity \nResources located in such LDA. \n \nPerformance Assessment Interval: \n \n“Performance Assessment Interval” shall have the meaning specified in Tariff, Attachment DD. \n \n \nPJM: \n \n \n“PJM” shall mean PJM Interconnection, L.L.C., including the Office of the Interconnection as \nreferenced in the PJM Operating Agreement.  When such term is being used in the RAA it shall \nalso include the PJM Board. \n \n \nPJM Board: \n \n \n“PJM Board” shall mean the Board of Managers of the  LLC, acting pursuant to the Operating \nAgreement, except when such term is being used in Tariff, Attachment M, in which case PJM \nBoard shall mean the Board of Managers of PJM or its designated representative, exclusive of \nany members of PJM Management. \n \n \nPJM Governing Agreements: \n \n“PJM Governing Agreements” shall have the meaning provided in the Operating Agreement. \n \nPJM Manuals: \n \n \n“PJM Manuals” shall mean the instructions, rules, procedures and guidelines established by the \nOffice of the Interconnection for the operation, planning and accounting requirements of the PJM \nRegion. \n \nPJM Region: \n \n \n“PJM Region” shall have the same meaning as provided in the Operating Agreement."},{"page":129,"startToken":44814,"endToken":45273,"text":"PJM Region Installed Reserve Margin: \n \n \n“PJM Region Installed Reserve Margin” shall mean the percent installed reserve margin for the \nPJM Region required pursuant to Reliability Assurance Agreement, Schedule 4.1, as approved \nby the PJM Board. \n \nPJM Tariff, Tariff, O.A.T.T., OATT or PJM Open Access Transmission Tariff: \n \n \n“PJM Tariff,” “Tariff,” “O.A.T.T., “OATT” or “PJM Open Access Transmission Tariff” shall \nmean that certain PJM Open Access Transmission Tariff, including any schedules, appendices, \nor exhibits attached thereto, on file with FERC and as amended from time to time thereafter. \n \n \nPlanned Demand Resource: \n \n \n“Planned Demand Resource” shall mean any Demand Resource that does not currently have the \ncapability to provide a reduction in demand or to otherwise control load, but that is scheduled to \nbe capable of providing such reduction or control on or before the start of the Delivery Year for \nwhich such resource is to be committed, as determined in accordance with the requirements of \nReliability Assurance Agreement, Schedule 6.  As set forth in Reliability Assurance Agreement, \nSchedule 6 and Reliability Assurance Agreement, Schedule 8.1, a Demand Resource Provider \nsubmitting a DR Sell Offer Plan shall identify as Planned Demand Resources in such plan all \nDemand Resources in excess of those that qualify as Existing Demand Resources. \n \n \nPlanned DER Capacity Aggregation Resource: \n \nA “Planned DER Capacity Aggregation Resource” shall mean any DER Capacity Aggregation \nResource that does not currently have the capability to provide generation or reduction in \ndemand, but that is scheduled to be capable of providing such generation or reduction in demand \non or before the start of the Delivery Year for which such resource is to be committed, as \ndetermined in accordance with the requirements of Reliability Assurance Agreement, Schedule \n6.2.  As set forth in Reliability Assurance Agreement, Schedule 6.2 and Reliability Assurance \nAgreement, Schedule 8.1, a DER Aggregator submitting a DER Capacity Aggregation Resource \nSell Offer Plan shall identify in such plan all DER Capacity Aggregation Resources in excess of \nthose that qualify as Existing DER Capacity Aggregation Resources.  A Planned DER Capacity \nAggregation Resource must comply with all provisions of the DER Aggregator Participation \nModel described in Tariff, Attachment K-Appendix, section 1.4B and Operating Agreement, \nSchedule 1, section 1.4B, prior to the applicable Delivery Year. \n \nPlanned External Generation Capacity Resource: \n \n \n“Planned External Generation Capacity Resource” shall mean a proposed Generation Capacity \nResource, or a proposed increase in the capability of a Generation Capacity Resource, that (a) is \nto be located outside the PJM Region, (b) participates in the generation interconnection process \nof a Control Area external to PJM, (c) is scheduled to be physically and electrically \ninterconnected to the transmission facilities of such Control Area on or before the first day of the"},{"page":130,"startToken":45273,"endToken":45917,"text":"Delivery Year for which such resource is to be committed to satisfy the reliability requirements \nof the PJM Region, and (d) is in full commercial operation prior to the first day of such Delivery \nYear, such that it is sufficient to provide the Installed Capacity set forth in the Sell Offer forming \nthe basis of such resource’s commitment to the PJM Region.  Prior to participation in any Base \nResidual Auction for such Delivery Year, the Capacity Market Seller must demonstrate that it \nhas documentation which is functionally equivalent to an approved Decision Point I submission \nunder the PJM Tariff Part VII or VIII as applicable or, for resources which are greater than \n20MWs participating in a Base Residual Auction for the 2019/2020 Delivery Year and \nsubsequent Delivery Years, an agreement or other documentation which is functionally \nequivalent to an approved Decision Point II submission under the PJM Tariff Part VII or VIII as \napplicable, with the transmission owner to whose transmission facilities or distribution facilities \nthe resource is being directly connected, and, as applicable, the transmission provider.  Prior to \nparticipating in any Incremental Auction for such Delivery Year, the Capacity Market Seller \nmust demonstrate it has entered into an interconnection agreement, or such other documentation \nthat is functionally equivalent to a Generation Interconnection Agreement under the PJM Tariff, \nwith the transmission owner to whose transmission facilities or distribution facilities the resource \nis being directly connected, and, as applicable, the transmission provider.  A Planned External \nGeneration Capacity Resource must provide evidence to PJM that it has been studied as a \nNetwork Resource, or such other similar interconnection product in such external Control Area, \nmust provide contractual evidence that it has applied for or purchased transmission service to be \ndeliverable to the PJM border, and must provide contractual evidence that it has applied for \ntransmission service to be deliverable to the bus at which energy is to delivered, the agreements \nfor which must have been executed prior to participation in any Reliability Pricing Model \nAuction for such Delivery Year. Any such resource shall cease to be considered a Planned \nExternal Generation Capacity Resource as of the earlier of (i) the date that interconnection \nservice commences as to such resource; or (ii) the resource has cleared an RPM Auction, in \nwhich case it shall become an Existing Generation Capacity Resource for purposes of the \nmitigation of offers for any RPM Auction for all subsequent Delivery Years.   \n \n \nPlanned Generation Capacity Resource: \n \n \n“Planned Generation Capacity Resource” shall mean a Generation Capacity Resource, or \nadditional megawatts to increase the size of a Generation Capacity Resource that is being or has \nbeen modified to increase the number of megawatts of available installed capacity thereof,  \nparticipating in the generation interconnection process under Tariff, Part IV, Subpart A, Part VII \nor Part VIII, as applicable, for which: (i) Interconnection Service is scheduled to commence on \nor before the first day of the Delivery Year for which such resource is to be committed to RPM \nor to an FRR Capacity Plan; (ii) for any such resource seeking to offer into a Base Residual \nAuction, or for any such resource of 20 MWs or less seeking to offer into a Base Residual \nAuction, all the requirements for an approved Decision Point I submission have been met under \nTariff Part VII or VIII (or, for resources for which a Decision Point I submission is not required, \nhas such other agreement or documentation that is functionally equivalent to a an approved \nDecision Point I submission) prior to the Base Residual Auction for such Delivery Year; (iii) for \nany such resource of more than 20 MWs seeking to offer into a Base Residual Auction for the \n2019/2020 Delivery Year and subsequent Delivery Years, all the requirements for an approved \nDecision Point II submission have been met under Tariff Part VII or VIII (or, for resources for"},{"page":131,"startToken":45917,"endToken":46315,"text":"which a Decision Point II submission is not required, has such other agreement or documentation \nthat is functionally equivalent to an approved Decision Point II submission) has been executed \nprior to the Base Residual Auction for such Delivery Year; and (iv) a Generation Interconnection \nAgreement or Wholesale Market Participation Agreement has been executed prior to any \nIncremental Auction for such Delivery Year in which such resource plans to participate.  For \npurposes of the must-offer requirement and mitigation of offers for any RPM Auction for a \nDelivery Year, a Generation Capacity Resource shall cease to be considered a Planned \nGeneration Capacity Resource as of the earlier of (i) the date that Interconnection Service \ncommences as to such resource; or (ii) the resource has cleared an RPM Auction for any \nDelivery Year, in which case it shall become an Existing Generation Capacity Resource for any \nRPM Auction for all subsequent Delivery Years.   \n \n \nPlanning Period: \n \n \n“Planning Period” shall mean the 12 months beginning June 1 and extending through May 31 of \nthe following year, or such other period approved by the Members Committee. \n \n \nPortfolio Expected Unserved Energy: \n \n“Portfolio Expected Unserved Energy” shall mean the annual amount of expected unserved \nenergy, in MWh, that is expected for the RTO when at the annual reliability criteria that provides \nan acceptable level of reliability consistent with the Reliability Principles and Standards. \n \nPRD Curve: \n \n“PRD Curve” shall mean a price-consumption curve at a PRD Substation level, if available, and \notherwise at a Zonal (or sub-Zonal LDA, if applicable) level, that details the base consumption \nlevel of Price Responsive Demand and the decreasing consumption levels at increasing prices. \n \nPRD Provider:  \n \n“PRD Provider” shall mean a PJM Member that has entered contractual arrangements with end-\nuse customers that satisfy the eligibility criteria for and provides Price Responsive Demand. \n \nPRD Provider’s Zonal Expected Peak Load Value of PRD:  \n \n“PRD Provider’s Zonal Expected Peak Load Value of PRD” shall mean the expected \ncontribution to Delivery Year peak load of a PRD Provider’s Price Responsive Demand, were \nsuch demand not to be reduced in response to price, based on the contribution of the end-use \ncustomers comprising such Price Responsive Demand to the most recent prior Delivery Year’s \npeak demand, escalated to the Delivery Year in question, as determined in a manner consistent \nwith the Office of the Interconnection’s load forecasts used for purposes of the RPM Auctions. \n \nPRD Reservation Price:"},{"page":132,"startToken":46315,"endToken":46715,"text":"“PRD Reservation Price” shall mean an RPM Auction clearing price identified in a PRD Plan for \nPrice Responsive Demand load below which the PRD Provider desires not to commit the \nidentified load as Price Responsive Demand. \n  \nPRD Substation: \n \n“PRD Substation” shall mean an electrical substation that is located in the same Zone or in the \nsame sub-Zonal LDA as the end-use customers identified in a PRD Plan or PRD registration and \nthat, in terms of the electrical topography of the Transmission Facilities comprising the PJM \nRegion, is as close as practicable to such loads. \n \nPrice Responsive Demand: \n \n“Price Responsive Demand” or “PRD” shall mean end-use customer load registered by a PRD \nProvider pursuant to Reliability Assurance Agreement, Schedule 6.1 that have, as set forth in \nmore detail in the PJM Manuals, the metering capability to record electricity consumption at an \ninterval of one hour or less, Supervisory Control capable of curtailing such load (consistent with \napplicable RERRA requirements) at each PRD Substation identified in the relevant PRD Plan or \nPRD registration in response to a Performance Assessment Interval that triggers a PRD \nperformance assessment or a Non-PAI Event, and a retail rate structure, or equivalent contractual \narrangement, capable of changing retail rates as frequently as an hourly basis, that is linked to or \nbased upon changes in real-time Locational Marginal Prices at a PRD Substation level and that \nresults in a predictable automated response to varying wholesale electricity prices. \n \nPrice Responsive Demand Credit: \n \n“Price Responsive Demand Credit” shall mean a credit, based on committed Price Responsive \nDemand, as determined under Reliability Assurance Agreement, Schedule 6.1. \n \nPrice Responsive Demand Plan or PRD Plan: \n \n“Price Responsive Demand Plan” or “PRD Plan” shall mean a plan, submitted by a PRD \nProvider and received by the Office of the Interconnection in accordance with Reliability \nAssurance Agreement, Schedule 6.1 and procedures specified in the PJM Manuals, claiming a \npeak demand limitation due to Price Responsive Demand to support the determination of such \nPRD Provider’s Nominal PRD Value. \n \nPublic Power Entity: \n \n \n“Public Power Entity” shall mean any agency, authority, or instrumentality of a state or of a \npolitical subdivision of a state, or any corporation wholly owned by any one or more of the \nforegoing, that is engaged in the generation, transmission, and/or distribution of electric energy. \n \n \nQualifying Transmission Upgrades: \n \n \n“Qualifying Transmission Upgrades” shall have the meaning specified in Tariff, Attachment DD."},{"page":133,"startToken":46715,"endToken":47067,"text":"Relevant Electric Retail Regulatory Authority: \n \n“Relevant Electric Retail Regulatory Authority” or “RERRA” shall have the meaning specified \nin the PJM Operating Agreement. \n \nReliability Principles and Standards: \n \n \n“Reliability Principles and Standards” shall mean the principles and standards established by  the \nOffice of the Interconnection that define, among other things, an acceptable probabilistic of loss \nof load criteria due to inadequate generation or transmission capability, as amended from time to \ntime. \n \n \nRequired Approvals: \n \n \n“Required Approvals” shall mean all of the approvals required for the Operating Agreement to \nbe modified or to be terminated, in whole or in part, including the acceptance for filing by FERC \nand every other regulatory authority with jurisdiction over all or any part of the Operating \nAgreement. \n \n \nSelf-Supply: \n \n \n“Self-Supply” shall have the meaning provided in Tariff, Attachment DD. \n \nSmall Commercial Customer: \n \n“Small Commercial Customer” shall have the same meaning as in the PJM Tariff. \n \n \nState Consumer Advocate: \n \n \n“State Consumer Advocate” shall mean a legislatively created office from any State, all or any \npart of the territory of which is within the PJM Region, and the District of Columbia established, \ninter alia, for the purpose of representing the interests of energy consumers before the utility \nregulatory commissions of such states and the District of Columbia and the FERC.  \n \n \nState Regulatory Structural Change: \n \n \n“State Regulatory Structural Change” shall mean as to any Party, a state law, rule, or order that, \nafter September 30, 2006, initiates a program that allows retail electric consumers served by such \nParty to choose from among alternative suppliers on a competitive basis, terminates such a \nprogram, expands such a program to include classes of customers or localities served by such \nParty that were not previously permitted to participate in such a program, or that modifies retail \nelectric market structure or market design rules in a manner that materially increases the \nlikelihood that a substantial proportion of the customers of such Party that are eligible for retail \nchoice under such a program (a) that have not exercised such choice will exercise such choice; or \n(b) that have exercised such choice will no longer exercise such choice, including for example,"},{"page":134,"startToken":47067,"endToken":47492,"text":"without limitation, mandating divestiture of utility-owned generation or structural changes to \nsuch Party’s default service rules that materially affect whether retail choice is economically \nviable. \n \nSteam Class: \n \n“Steam Class” shall mean an ELCC Class consisting of Unlimited Resources of the steam \ntechnology type and the primary fuel is not coal or nuclear. \n \nSummer-Period Demand Resource: \n \nSummer-Period Demand Resource shall mean, for the 2020/2021 Delivery Year and subsequent \nDelivery Years, a resource that is placed under the direction of the Office of the Interconnection, \nand will be available June through October and the following May of the Delivery Year, and will \nbe available for an unlimited number of interruptions during such months by the Office of the \nInterconnection, and will be capable of maintaining each such interruption between the hours of \n10:00AM to 10:00PM Eastern Prevailing Time.  The Summer-Period Demand Resource must be \navailable June through October and the following May in the corresponding Delivery Year to be \noffered for sale in an RPM Auction, or included as a Summer-Period Demand Resource in an \nFRR Capacity Plan for the corresponding Delivery Year. \n \nSummer-Period Energy Efficiency Resource:  \n \nSummer-Period Energy Efficiency Resource shall mean, for the 2020/2021 Delivery Year and \nsubsequent Delivery Years, a project, including installation of more efficient devices or \nequipment or implementation of more efficient processes or systems, meeting the requirements \nof Reliability Assurance Agreement, Schedule 6 and exceeding then-current building codes, \nappliance standards, or other relevant standards, designed to achieve a continuous (during the \nsummer peak periods as described in Reliability Assurance Agreement, Schedule 6 and the PJM \nManuals) reduction in electric energy consumption that is not reflected in the peak load forecast \nprepared for the Delivery Year for which the Summer-Period Energy Efficiency Resource is \nproposed, and that is fully implemented at all times during such Delivery Year, without any \nrequirement of notice, dispatch, or operator intervention. \n \nSupervisory Control: \n \n“Supervisory Control” shall mean the capability to curtail, in accordance with applicable \nRERRA requirements, load registered as Price Responsive Demand at each PRD Substation \nidentified in the relevant PRD Plan or PRD registration in response to a Maximum Generation \nEmergency declared by the Office of the Interconnection.  Except to the extent automation is not \nrequired by the provisions of the Operating Agreement, the curtailment shall be automated, \nmeaning that load shall be reduced automatically in response to control signals sent by the PRD \nProvider or its designated agent directly to the control equipment where the load is located \nwithout the requirement for any action by the end-use customer. \n \n \nThreshold Quantity:"},{"page":135,"startToken":47492,"endToken":47900,"text":"“Threshold Quantity” shall mean, as to any FRR Entity for any Delivery Year, the sum of (a) the \nUnforced Capacity equivalent (determined using the Pool-Wide Average EFORD through the \n2024/2025 Delivery Year, or pool-wide average Accredited UCAP Factor effective with the \n2025/2026 Delivery Year) of the Installed Reserve Margin for such Delivery Year multiplied by \nthe Preliminary Forecast Peak Load for which such FRR Entity is responsible under its FRR \nCapacity Plan for such Delivery Year, plus (b) the lesser of (i) 3% of the Unforced Capacity \namount determined in (a) above or (ii) 450 MW.  If the FRR Entity is not responsible for all load \nwithin a Zone, the Preliminary Forecast Peak Load for such entity shall be determined in \naccordance with Reliability Assurance Agreement, Schedule 8.1, section D.2. \n \n \nTracking Solar Class: \n \n“Tracking Solar Class” shall mean an ELCC Class consisting of Variable Resources that produce \nelectrical energy with solar panels that are primarily mounted on trackers that align the panels \nwith incoming sunlight over the course of the day. \n \nTransmission Facilities: \n \n \n“Transmission Facilities” shall mean facilities that:  (i) are within the PJM Region; (ii) meet the \ndefinition of transmission facilities pursuant to FERC’s Uniform System of Accounts or have \nbeen classified as transmission facilities in a ruling by FERC addressing such facilities; and (iii) \nhave been demonstrated to the satisfaction of the Office of the Interconnection to be integrated \nwith the PJM Region transmission system and integrated into the planning and operation of the \nPJM Region to serve all of the power and transmission customers within the PJM Region. \n \n \nTransmission Owner: \n \n \n“Transmission Owner” shall mean a Member that owns or leases with rights equivalent to \nownership Transmission Facilities and is a signatory to the PJM Transmission Owners \nAgreement.  Taking transmission service shall not be sufficient to qualify a Member as a \nTransmission Owner. \n \n \nUnforced Capacity: \n \n \n“Unforced Capacity” shall mean installed capacity rated at summer conditions that is not on \naverage experiencing a forced outage or forced derating, calculated for each Capacity Resource \non the 12-month period from October to September without regard to the ownership of or the \ncontractual rights to the capacity of the unit. \n \nUnlimited Resource: \n \n“Unlimited Resource” shall mean a generating unit having the ability to maintain output at a \nstated capability continuously on a daily basis without interruption.  Through the 2024/2025 \nDelivery Year, an Unlimited Resource is a Generation Capacity Resource that is not an ELCC \nResource."},{"page":136,"startToken":47900,"endToken":48348,"text":"Variable Resource: \n \n“Variable Resource” shall mean a Generation Capacity Resource or a generation Component \nDER within a DER Aggregation Resource that is linked to a DER Capacity Aggregation \nResource, with output that can vary as a function of its energy source, such as wind, solar, run of \nriver hydroelectric power without storage, and landfill gas units without an alternate fuel source.  \nAll Intermittent Resources are Variable Resources, with the exception of Hydropower with Non-\nPumped Storage. \n \n \nWinter Peak Load (or WPL): \n \n“Winter Peak Load” or “WPL” shall mean the average of the Demand Resource customer’s \nspecific peak hourly load between hours ending 7:00 EPT through 21:00 EPT on the PJM \ndefined 5 coincident peak days from December through February two Delivery Years prior the \nDelivery Year for which the registration is submitted.  Notwithstanding, if the average use \nbetween hours ending 7:00 EPT through 21:00 EPT on a winter 5 coincident peak day is below \n35% of the average hours ending 7:00 EPT through 21:00 EPT over all five of such peak days, \nthen up to two such days and corresponding peak demand values may be excluded from the \ncalculation.  Upon approval by the Office of the Interconnection, a Curtailment Service Provider \nmay provide alternative data to calculate Winter Peak Load, as outlined in the PJM Manuals, \nwhen there is insufficient hourly load data for the two Delivery Years prior to the relevant \nDelivery Year or if more than two days meet the exclusion criteria described above. \n \nZonal Capacity Price: \n \n \n“Zonal Capacity Price” shall mean the clearing price required in each Zone to meet the demand \nfor Unforced Capacity and satisfy Locational Deliverability Requirements for the LDA or LDAs \nassociated with such Zone.  If the Zone contains multiple LDAs with different Capacity \nResource Clearing Prices, the Zonal Capacity Price shall be a weighted average of the Capacity \nResource Clearing Prices for such LDAs, weighted by the Unforced Capacity of Capacity \nResources cleared in each such LDA.   \n \n \nZone or Zonal: \n \n \n“Zone” or “Zonal” shall refer to an area within the PJM Region, as set forth in Tariff, \nAttachment J and RAA, Schedule 15, or as such areas may be (i) combined as a result of mergers \nor acquisitions or (ii) added as a result of the expansion of the boundaries of the PJM Region.  A \nZone shall include any Non-Zone Network Load located outside the PJM Region that is served \nfrom such Zone under Tariff, Attachment H-A. \n \nZonal Winter Weather Adjustment Factor (ZWWAF): \n \n“Zonal Winter Weather Adjustment Factor” or “ZWWAF” shall mean the PJM zonal winter \nweather normalized  coincident peak  divided by PJM zonal average of 5 coincident peak loads in \nDecember through February."},{"page":137,"startToken":48348,"endToken":48548,"text":"7.8  \nRequirement to Designate Network Resources to Serve Capacity Needs for New \nLarge Loads and Conditional Requirement to Provide Interim Resource Adequacy Service \n \nEffective June 1, 2027, each LSE that desires to provide Network Transmission Service to support \nNew Large Loads must designate one or more Generation Capacity Resources or Capacity Storage \nResources that had not cleared an RPM Auction as Network Resource(s) in a cumulative amount \nthat equals or exceeds the LSE’s New Large Load’s peak load (in MW) as reported in the Large \nLoad Registry pursuant to RAA, Schedule 11 or such New Large Load may be subject to load \nreduction requests during Emergencies prior to Pre-Emergency Load Management Response.  If, \non June 1, 2027, an LSE has not so designated such Network Resource(s) as BYONC with which \nit has entered into an arrangement in accordance with this requirement and Tariff, Attachment DD-\n4, then the amount of New Large Load that is the difference between its reported peak load and its \ndesignated Bring Your Own New Capacity and assigned Allocated RBP UCAP MW will be \nsubject to the rates, terms, and conditions of Interim Resource Adequacy Service, as set forth in \nTariff, Attachment DD-4."},{"page":138,"startToken":48548,"endToken":49166,"text":"D. \nFRR Capacity Plans \n \n1. \nEach FRR Entity shall submit its initial FRR Capacity Plan as required by subsection C.1 \nof this Schedule, and shall annually extend and update such plan by no later than one month prior \nto the Base Residual Auction for each succeeding Delivery Year in such plan.  Each FRR \nCapacity Plan shall indicate the nature and current status of each resource, including the status of \neach Planned Generation Capacity Resource or Planned Demand Resource, the planned \ndeactivation or retirement of any Generation Capacity Resource or Demand Resource, and the \nstatus of commitments for each sale or purchase of capacity included in such plan. \n \n1.1 \nBeginning with the 2020/2021 Delivery Year and for all subsequent Delivery Years, the \nFRR Capacity Plan shall comprise only Capacity Performance Resources and Seasonal Capacity \nPerformance Resources.  An FRR Entity may not include in its FRR Capacity Plan any MW \nquantity of Existing Generation Capacity Resource in excess of what such FRR Entity owned or \ncontracted by such FRR Entity prior to June 1, 2027, to serve New Large Load. \n \n2. \nThe FRR Capacity Plan of each FRR Entity that commits that it will not sell surplus \nCapacity Resources as a Capacity Market Seller in any auction conducted under Attachment DD \nof the PJM Tariff, or to any direct or indirect purchaser that uses such resource as the basis of \nany Sell Offer in such auction, shall designate Capacity Resources in a megawatt quantity no less \nthan the Forecast Pool Requirement for each applicable Delivery Year times the FRR Entity’s \nallocated share of the Preliminary Zonal Peak Load Forecast for such Delivery Year, as \ndetermined in accordance with procedures set forth in the PJM Manuals.  If the FRR Entity is not \nresponsible for all load within a Zone, the Preliminary Forecast Peak Load for such entity shall \nbe the Base Zonal FRR Scaling Factor times the summation of the FRR Entity’s MW share of \nthe Zonal Weather Normalized Summer Peak last determined prior to the Base Residual Auction \nfor such Delivery Year plus the Obligation Peak Load MW associated with any Load Adjustment \nspecified for such Delivery Year for any “zone/area” served by the FRR Entity’s Capacity Plan.  \nThe Obligation Peak Load MW associated with a Load Adjustment specified for a “zonal/area” \nis determined as set forth in RAA, Schedule 8, section B. \n \nThe FRR Capacity Plan of each FRR Entity that does not commit that it will not sell surplus \nCapacity Resources as set forth above shall designate Capacity Resources at least equal to the \nThreshold Quantity.  To the extent the FRR Entity’s allocated share of the Final Zonal Peak \nLoad Forecast exceeds the FRR Entity’s allocated share of the Preliminary Zonal Peak Load \nForecast, such FRR Entity’s FRR Capacity Plan shall be updated to designate additional \nCapacity Resources in an amount no less than the Forecast Pool Requirement times such \nincrease; provided, however, any excess megawatts of Capacity Resources included in such FRR \nEntity’s previously designated Threshold Quantity, if any, may be used to satisfy the capacity \nobligation for such increased load.  To the extent the FRR Entity’s allocated share of the Final \nZonal Peak Load Forecast is less than the FRR Entity’s allocated share of the Preliminary Zonal \nPeak Load Forecast, such FRR Entity’s FRR Capacity Plan may be updated to release previously \ndesignated Capacity Resources in an amount no greater than the Forecast Pool Requirement \ntimes such decrease.  Peak load values referenced in this section shall be adjusted as necessary to \ntake into account any applicable Nominal PRD Values approved pursuant to Schedule 6.1 of this \nAgreement.  Any FRR Entity seeking an adjustment to peak load for Price Responsive Demand"},{"page":139,"startToken":49166,"endToken":49749,"text":"must submit a separate PRD Plan in compliance with Section 6.1 (provided that the FRR Entity \nshall not specify any PRD Reservation Price), and shall register all PRD-eligible load needed to \nsatisfy its PRD commitment and be subject to compliance charges as set forth in that Schedule \nunder the circumstances specified therein; provided that for non-compliance by an FRR Entity, \nthe compliance charge rate shall be equal to 1.20 times the Capacity Resource Clearing Price \nresulting from all RPM Auctions for such Delivery Year for the LDA encompassing the FRR \nEntity’s Zone, weight-averaged for the Delivery Year based on the prices established and \nquantities cleared in the RPM auctions for such Delivery Year; and provided further that an \nalternative PRD Provider may provide PRD in an FRR Service Area by agreement with the FRR \nEntity responsible for the load in such FRR Service Area, subject to the same terms and \nconditions as if the FRR Entity had provided the PRD. \n \n3. \nAs to any FRR Entity, the Base Zonal FRR Scaling Factor for each Zone in which it \nserves load for a Delivery Year shall equal [(ZPLDY-ZLA) / ZWNSP], where: \n \nZPLDY = Preliminary Zonal Peak Load Forecast for such Zone for such Delivery Year;  \n \nZLA = the Zonal MW quantity of Load Adjustment for such Delivery Year; and  \n \nZWNSP = Zonal Weather-Normalized Summer Peak Load for such Zone for the summer \nconcluding four years prior to the commencement of such Delivery Year. \n \n4. \nCapacity Resources identified and committed in an FRR Capacity Plan shall meet all \nrequirements under this Agreement, the PJM Tariff, and the PJM Operating Agreement \napplicable to Capacity Resources, including, as applicable, requirements and milestones for \nPlanned Generation Capacity Resources and Planned Demand Resources.  A Capacity Resource \nsubmitted in an FRR Capacity Plan must be on a unit-specific basis, and may not include “slice \nof system” or similar agreements that are not unit specific.  An FRR Capacity Plan may include \nbilateral transactions that commit capacity for less than a full Delivery Year only if the resources \nincluded in such plan in the aggregate satisfy all obligations for all Delivery Years.  All demand \nresponse, load management, energy efficiency, or similar programs on which such FRR Entity \nintends to rely for a Delivery Year must be included in the FRR Capacity Plan, subject to \napplicable demand resource constraints for the relevant Delivery Year, submitted three years in \nadvance of such Delivery Year and must satisfy all requirements applicable to Demand \nResources or Energy Efficiency Resources, as applicable, including, without limitation, those set \nforth in Schedule 6 to this Agreement and the PJM Manuals; provided, however, that previously \nuncommitted Unforced Capacity from such programs may be used to satisfy any increased \ncapacity obligation for such FRR Entity resulting from a Final Zonal Peak Load Forecast \napplicable to such FRR Entity.  Without limiting the generality of the foregoing, the FRR Entity \nmust submit a Demand Resource Sell Offer Plan 15 business days before the deadline for \nsubmitting an FRR Capacity Plan as to any Demand Resources it intends to include in such FRR \nCapacity Plan and may only include in such FRR Capacity Plan Demand Resources that are \napproved by PJM following review of such Demand Resource Sell Offer Plan.  The \nrequirements, standards, and procedures for a Demand Resource Sell Offer Plan shall be as set \nforth in Schedule 6 of this Agreement, provided that all references (including deadlines) in \nSchedule 6, section A-1 to submission or clearing of a Demand Resource offer in an RPM"},{"page":140,"startToken":49749,"endToken":50351,"text":"Auction shall be understood for purposes of FRR Entities as referring to inclusion of a Demand \nResource in an FRR Capacity Plan, and a distinct Demand Resource Officer Certification Form \nshall be applicable to FRR Entities, as shown in the PJM Manuals and provided on the PJM \nwebsite. \n \n5. \nFor each LDA for which the Office of the Interconnection is required to establish a \nseparate Variable Resource Requirement Curve for any Delivery Year addressed by such FRR \nCapacity Plan, the plan must include a Percentage Internal Resources Required, subject to \nsubsections D.1.1 and D.2 of this Schedule.  The Percentage Internal Resources Required will be \ncalculated as the LDA Reliability Requirement less the CETL for the Delivery Year, as \ndetermined by the RTEP process as set forth in the PJM Manuals.  Such requirement shall be \nexpressed as a percentage of the Unforced Capacity Obligation based on the Preliminary Zonal \nPeak Load Forecast multiplied by the Forecast Pool Requirement.  Notwithstanding the \nprovisions of Sections C.1 and C.2 of this Schedule 8.1, an FRR Entity may terminate its \nelection of the FRR Alternative prior to meeting its minimum five year commitment \nwithout penalty for any Delivery Year after the first Delivery Year of its minimum five \nyear FRR commitment for which the Office of the Interconnection will be required to \nestablish a separate Variable Resource Requirement Curve by giving written notice two \nmonths prior to the Base Residual Auction for the Delivery Year. The Office of the \nInterconnection shall be deemed to be required to establish a separate Variable Resource \nRequirement Curve for an LDA if the LDA is the Eastern Mid-Atlantic Region \n(“EMAR”), Southwest Mid-Atlantic Region (“SWMAR”), or Mid-Atlantic Region \n(“MAR”), or for other LDAs if the separate modeling is required by Section \n5.10(a)(ii)(A) or (B) of Attachment DD of the Tariff. \n \n6. \nAn FRR Entity may reduce the Percentage Internal Resources Required as to any LDA to \nthe extent the FRR Entity commits to a transmission upgrade that increases the CETL for such \nLDA.  Any such transmission upgrade shall adhere to all requirements for a Qualified \nTransmission Upgrade as set forth in Attachment DD to the PJM Tariff.  The increase in CETL \nused in the FRR Capacity Plan shall be that approved by PJM prior to inclusion of any such \nupgrade in an FRR Capacity Plan.  The FRR Entity shall designate specific additional Capacity \nResources located in the LDA from which the CETL was increased, to the extent of such \nincrease. \n \n7. \nThe Office of the Interconnection will review the adequacy of all submittals hereunder \nboth as to timing and content.  A Party that seeks to elect the FRR Alternative that submits an \nFRR Capacity Plan which, upon review by the Office of the Interconnection, is determined not to \nsatisfy such Party’s capacity obligations hereunder, shall not be permitted to elect the FRR \nAlternative.  If a previously approved FRR Entity submits an FRR Capacity Plan that, upon \nreview by the Office of the Interconnection, is determined not to satisfy such Party’s capacity \nobligations hereunder, the Office of the Interconnection shall notify the FRR Entity, in writing, \nof the insufficiency within five (5) business days after the submittal deadline of the FRR \nCapacity Plan.  Through the 2024/2025 Delivery Year, if the FRR Entity does not cure such \ninsufficiency within five (5) business days after receiving such notice of insufficiency, then such \nFRR Entity shall be assessed an FRR Commitment Insufficiency Charge, in an amount equal to \ntwo times the Cost of New Entry for the relevant location, in $/MW-day, times the shortfall of"},{"page":141,"startToken":50351,"endToken":50922,"text":"Capacity Resources below the FRR Entity’s capacity obligation (including any Threshold \nQuantity requirement) in such FRR Capacity Plan, for the remaining term of such plan. For \nDelivery Years between the 2025/2026 Delivery Year through the 2028/2029 Delivery Year, no \nFRR Commitment Insufficiency Charge shall be assessed. Effective with the 2029/2030 Delivery \nYear and subsequent Delivery Years, if the FRR Entity does not cure such insufficiency within \nfive (5) business days after receiving such notice of insufficiency, then such FRR Entity shall be \nassessed an FRR Commitment Insufficiency Charge, in an amount equal to the price level \ncorresponding to point (1) of the Variable Resource Requirement curve, as provided in Tariff, \nAttachment DD, section 5.10(a)(i), for the relevant Locational Deliverability Area, in $/MW-\nday, times the shortfall of Capacity Resources below the FRR Entity’s capacity obligation \n(including any Threshold Quantity requirement) in such FRR Capacity Plan, for such Delivery \nYear.  \n \n8. \nIn a state regulatory jurisdiction that has implemented retail choice, the FRR Entity must \ninclude in its FRR Capacity Plan all load, including expected load growth, in the FRR Service \nArea, notwithstanding the loss of any such load to or among alternative retail LSEs.  In the case \nof load reflected in the FRR Capacity Plan that switches to an alternative retail LSE, where the \nstate regulatory jurisdiction requires switching customers or the LSE to compensate the FRR \nEntity for its FRR capacity obligations, such state compensation mechanism will prevail.  In the \nabsence of a state compensation mechanism, the applicable alternative retail LSE shall \ncompensate the FRR Entity at the capacity price in the unconstrained portions of the PJM \nRegion, as determined in accordance with Attachment DD to the PJM Tariff, provided that the \nFRR Entity may, at any time, make a filing with FERC under Sections 205 of the Federal Power \nAct proposing to change the basis for compensation to a method based on the FRR Entity's cost \nor such other basis shown to be just and reasonable, and a retail LSE may at any time exercise its \nrights under Section 206 of the FPA. \n \n9. \nNotwithstanding the foregoing, in lieu of providing the compensation described above, \nsuch alternative retail LSE may, for any Delivery Year subsequent to those addressed in the FRR \nEntity’s then-current FRR Capacity Plan, provide to the FRR Entity Capacity Resources \nsufficient to meet the capacity obligation described in paragraph D.2 for the switched load. Such \nCapacity Resources shall meet all requirements applicable to Capacity Resources pursuant to this \nAgreement, the PJM Tariff, and the PJM Operating Agreement, all requirements applicable to \nresources committed to an FRR Capacity Plan under this Agreement, and shall be committed to \nservice to the switched load under the FRR Capacity Plan of such FRR Entity.  The alternative \nretail LSE shall provide the FRR Entity all information needed to fulfill these requirements and \npermit the resource to be included in the FRR Capacity Plan.  The alternative retail LSE, rather \nthan the FRR Entity, shall be responsible for any performance charges or compliance penalties \nrelated to the performance of the resources committed by such LSE to the switched load.  For \nany Delivery Year, or portion thereof, the foregoing obligations apply to the alternative retail \nLSE serving the load during such time period.  PJM shall manage the transfer accounting \nassociated with such compensation and shall administer the collection and payment of amounts \npursuant to the compensation mechanism."},{"page":142,"startToken":50922,"endToken":50961,"text":"Such load shall remain under the FRR Capacity Plan until the effective date of any termination \nof the FRR Alternative and, for such period, shall not be subject to Locational Reliability \nCharges under Section 7.2 of this Agreement."},{"page":143,"startToken":50961,"endToken":51319,"text":"SCHEDULE 11 \n \nDATA SUBMITTALS \n \nA. \nTo perform the studies required to determine the Forecast Pool Requirement and Daily \nUnforced Capacity Obligations under this Agreement and to determine compliance with the \nobligations imposed by this Agreement, each Party and other owner of a Capacity Resource shall \nsubmit data to the Office of the Interconnection in conformance with the following minimum \nrequirements: \n \n1. \nAll data submitted shall satisfy the requirements, as they may change from time to time, of \nany procedures adopted by the Members Committee. \n \n2. \nData shall be submitted in an electronic format, or as otherwise specified by the Markets \nand Reliability Committee and approved by the PJM Board. \n \n3. \nActual outage data for each month for Generator Forced Outages, Generator Maintenance \nOutages and Generator Planned Outages shall be submitted so that it is received by such \ndate specified in the PJM Manuals. \n \n4. \nOn or before the date specified in the PJM Manuals, planned and maintenance outage data \nfor all Generation Resources shall be submitted. \n \n \nThe Parties acknowledge that additional information required to determine the Forecast Pool \nRequirement is to be obtained by the Office of the Interconnection from Electric Distributors in \naccordance with the provisions of the Operating Agreement. \n \nB. \n1. \n(a) \nEach Party shall submit, or cause to be submitted, to the Office of the \nInterconnection the following information, as may be further described in the PJM \nManuals, related to each Large Load served by the Party: \n \n Eligible Customer/Network Customer for Large Load; \n Description of Large Load; \n Location(s) (Control Zone, Electric Distributor zone/area, where a \nzone/area is an area within a Zone for which the relevant Electric \nDistributor specifies a separate Obligation Peak Load MW value. A \nzone/area is a service area of an Electric Distributor that is a separately \nidentifiable, geographic area bounded by wholesale metering); \n In-service date for each increment of load; \n Peak shaving adjustment value pursuant to a state program codified in \nstate law and whether and how it meets the requirements of Tariff, \nAttachment DD-2; \n Delivery point / Point(s) of interconnection (include all if more than \none); \n Peak load quantity (MW) and ramp schedule, if applicable;"},{"page":144,"startToken":51319,"endToken":51728,"text":" Telemetry specifications; \n BYONC quantity (MW) and ramp schedule, if applicable; \n Allocated RBP UCAP MW quantity (MW), if applicable; \n Backup generation (MW), including fuel type and relevant permitting \nlimitations; \n Contracts or service agreements between the Large Load and the LSE; \n Points of contact at the applicable Transmission Owner, Electric \nDistributor, and Load Serving Entity; \n EMS B1/B2/B3 name (for the applicable Transmission Owner, Electric \nDistributor); and  \n Additional details and contents as necessary, in accordance with the \nPJM Manuals. \n \n(b) \nThe Parties acknowledge that information related to the development and \nmaintenance of the Large Load Registry may be obtained by the Office of the \nInterconnection from Electric Distributors in accordance with the provisions of the \nOperating Agreement and the Tariff.   \n \n(c) \nThe Office of the Interconnection may review information and coordinate \nwith the applicable Transmission Owner and Electric Distributor as needed, regarding the \nvalidity of the information provided, including through requesting additional information \nas the Office of the Interconnection deems necessary, as further set forth in the PJM \nManuals.  The Office of the Interconnection also may consult with the Large Load. \n \n(d) \nBased on the information provided, or caused to be provided, by each Party, \nas well as other information provided by, for example, Electric Distributors, the Office of \nthe Interconnection shall maintain a registry of all Large Loads, and update it periodically.  \nTo the extent such documents, data, or other information provided to the Office of the \nInterconnection has been designated as confidential by a Party, Electric Distributor, or \nother entity supplying the information, the Office of the Interconnection shall maintain the \nconfidentiality of the information provided under this RAA, Schedule 11, section B \nconsistent with its obligations under Operating Agreement, section 18.17.  Information \nmaintained in the Large Load registry may be available to Authorized Commissions, \nTransmission Owners, Electric Distributors, Load Serving Entities, the Market Monitoring \nUnit, and FERC subject to appropriate data protection safeguards required by Operating \nAgreement, section 18.17. \n \n(e) \nThe Office of the Interconnection shall post aggregate data from the Large \nLoad Registry on the PJM website, aggregated by Electric Distributor zone/area, where \npossible and in a manner consistent with existing confidentiality protections in the PJM \nGoverning Agreements. \n \n2. \n(a) \nEach Party serving or contracted to serve a Large Load that is or will be in \nservice prior to June 1, 2027, shall provide the information required by RAA, Schedule \n11.B.1 to the Office of the Interconnection by March 1, 2027."},{"page":145,"startToken":51728,"endToken":52007,"text":"(b) \nEach Party serving or contracted to serve a New Large Load that will be in \nservice on or after June 1, 2027, shall provide the information required by RAA, Schedule \n11.B.1 to the Office of the Interconnection before the in-service date of the Large Load. \n \n(c) \nEach Party contracted to serve a New Large Load shall provide the \nlocation(s) as required by RAA, Schedule 11.B.1 to the Office of the Interconnection \nbefore determination of the final PJM Regional Peak Load Forecast for the effective RPM \nAuction for the Delivery Year in which the New Large Load is expected to be in-service \nstarting with the 2028 PJM Regional Peak Load Forecast. \n \nEach Party shall promptly inform the Office of the Interconnection of any change in the \ninformation required by RAA, Schedule 11.B.1 with respect to a Large Load served by the \nParty, including whether the Party no longer serves the Large Load or has acquired the \ncontractual right to serve a registered Large Load. \n \n3. \nThe information provided pursuant to RAA, Schedule 11, section B will be used, \nto the extent necessary, for purposes including but not limited to implementation of Interim \nResource Adequacy Service, which is a load reduction service, effective starting with the \n2027/2028 Delivery Year, through which Eligible New Large Loads may be compensated for \nproviding load reductions requested by the Office of the Interconnection to maintain system \nreliability for the purpose of supporting the integration of New Large Loads to the PJM Region \nthat have not entered into an arrangement with new capacity additions to the PJM Region, as more \nfully set forth in Tariff, Attachment DD-4."}],"sections":[{"p":1,"at":0,"title":"Attachment B","method":"printed heading","endPage":2,"endAt":0,"startToken":0,"endToken":16},{"p":2,"at":0,"title":"Definitions – A - 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