{"document":{"slug":"compliance-er26-3515-pjm","title":"Thirty-Day Compliance Filing on PJM’s Large Load Definition and Large Load Registry","issued":"2026-11-09","accession":"20261109-5217","docket":"ER26-3515-002","group":"PJM Large Load definition, Registry and Interim Resource Adequacy Service","filer":"PJM","kind":"compliance filing","file":"sources/originals/20261109-5217_PJM compliance filing.pdf","url":"https://www.pjm.com/pjmfiles/directory/etariff/FercDockets/9976/20261109-er26-3515-002.pdf","sha256":"092e39a95b0fcd6cdd7c05d842d70fe0f9121a4a446026164614bf98ba029f6f","pages":125,"tokens":41534,"emptyPages":[]},"pages":[{"page":1,"startToken":0,"endToken":217,"text":"PJM Interconnection, L.L.C. \n2750 Monroe Blvd \nAudubon, PA 19403 \n   Mark J. Stanisz \nAssociate General Counsel \nT: (610) 666-4707 | (F) (610) 666-8211 \nMark.Stanisz@pjm.com \nNovember 9, 2026 \nThe Honorable Debbie-Anne A. \nReese Secretary \nFederal Energy Regulatory \nCommission 888 First Street, N.E. \nRoom 1A Washington, D.C. 20426 \nRe: \n \nPJM Interconnection L.L.C., Docket No. ER26-3515-002;\nThirty-Day Compliance Filing to the Commission’s October 9, 2026 Order on PJM’s \nLarge Load Definition and Large Load Registry  \nDear Secretary Reese: \nPursuant to the October 9, 2026 Order of the Federal Energy Regulatory \nCommission (“Commission”) in Docket No. ER26-3515-000,1 PJM Interconnection, \nL.L.C. (“PJM”) submits this compliance filing to comply with the directives set forth in\nthe October 9 Order on PJM’s Proposed Revisions to its Open Access Transmission Tariff \n(“OATT”) and Reliability Assurance Agreement (“RAA”).2\n1 PJM Interconnection, L.L.C., 197 FERC ¶ 61,019 (2026) (“October 9 Order”). \n2 The compliance directives are set forth in the following paragraphs of the October 9 Order:  13, 14, 27, 32, 48 & n. \n101 (“we find that PJM’s proposed Large Load Registry as described in proposed OATT, Attachment DD-4, § II(a), \nIII(b), and proposed RAA Schedule 11 revisions in sections (B)(1), B(2)(a), and B(2)(b)”), 49, 50 & n. 102."},{"page":2,"startToken":217,"endToken":484,"text":"Debbie Anne-A. Reese, Secretary \nNovember 9, 2026 \nPage 2 of 3 \n \n \nConsistent with the October 9 Order, PJM submits on compliance the \nCommission-accepted definition of “Large Load” and OATT, Attachment DD-4, § \nII(a), III(b), and RAA Schedule 11 revisions in sections (B)(1), B(2)(a), and B(2)(b).3  \nPJM’s submission also reflects clarifications that the Commission accepted regarding \nthe meaning of the term “Party” as used in the language relating to the Large Load \nRegistry in the RAA.4  PJM has also updated the information that must be provided for \ninclusion in the Large Load Registry to remove previously identified items that are part \nof the IRAS package (specifically, the amount of BYONC brought by a particular Large \nLoad and the allocated RBP UCAP MW quantity).  Because the Commission found \nRAA, Schedule 11, section (B)(1) just and reasonable, PJM has filed on compliance \nthe obligation to update the information required by this section (B)(1).  This obligation \nwas previously filed in an unnumbered provision of Schedule 11, section (B)(2).     \nIn accordance with the Commission’s directives in the October 9 Order, PJM \nsubmits the proposed revisions to be effective as of October 12, 2026. \n \nI. \nDESCRIPTION OF SUBMITTAL \n \nThis filing consists of the following: \n \n1. This transmittal letter; \n \n2. Attachment A – Revisions to the OATT and RAA in redline (marked) \nformat; and \n \n3. Attachment B – Revisions to the OATT and RAA in clean format. \n \n \n \n3 RAA Schedule 11, section B(2)(b) has been revised given the order’s discussion of “New Large Load.”   \n4 October 9 Order at P 50 & n. 102."},{"page":3,"startToken":484,"endToken":692,"text":"Debbie Anne-A. Reese, Secretary \nNovember 9, 2026 \nPage 3 of 3 \n \n \nII. \nSERVICE \nPJM has served a copy of this filing on all PJM Members and on all state \nutility regulatory commissions in the PJM Region by posting this filing \nelectronically. In accordance with the Commission’s regulations,10  PJM will post \na copy of this filing to the FERC filings section of its internet site, located at the \nfollowing link: https://www.pjm.com/library/filing-order with a specific link to the \nnewly-filed document, and will send an e-mail on the same date as this filing to all \nPJM Members and all state utility regulatory commissions in the PJM Region5 \nalerting them that this filing has been made by PJM and is available by following \nsuch link. If the document is not immediately available by using the referenced link, \nthe document will be available through the referenced link within 24 hours of the \nfiling.  Also, a copy of this filing will be available on the FERC’s eLibrary website \nlocated at the following link: http://www.ferc.gov/docsfiling/elibrary.asp in \naccordance with the Commission’s regulations and Order No. 714. \n \n \n \n \n \n5 PJM already maintains, updates and regularly uses e-mail lists for all PJM Members and affected state \ncommissions."},{"page":4,"startToken":692,"endToken":789,"text":"Debbie Anne-A. Reese, Secretary \nNovember 9, 2026 \nPage 4 of 3 \n \n \nIII. \nCONCLUSION \n \nIn accordance with the foregoing, PJM respectfully requests that the \nCommission accept this compliance filing, as discussed here. \nRespectfully submitted, \n \n/s/ Mark J. Stanisz \n \n          Craig Glazer \n          Vice President – Federal    \n           Government Policy  \n          PJM Interconnection, L.L.C. \n          1200 G Street,    \n             N.W. Suite 600 \n          Washington, D.C. 20005 \n          (202) 423-4743 \n          Craig.Glazer@pjm.com \nMark J. Stanisz \nAssociate General Counsel  \nPJM Interconnection, L.L.C.  \n2750 Monroe Boulevard \nAudubon, PA 19403 \n(610) 666-4707 \nMark.Stanisz@pjm.com \n \n \nOn behalf of PJM Interconnection, L.L.C."},{"page":5,"startToken":789,"endToken":845,"text":"CERTIFICATE OF SERVICE \n \nI hereby certify that I have this 9th day of November, 2026 caused a copy of the \nforegoing document to be served upon each person designated on the official service list \ncompiled by the Secretary in this proceeding. \n/s/ Mark J. Stanisz \nMark J. Stanisz \nAssociate General Counsel \nPJM Interconnection, L.L.C."},{"page":6,"startToken":845,"endToken":868,"text":"Attachment A \nRevisions to the  \nPJM Open Access Transmission Tariff and \nReliability Assurance Agreement \n(Marked Format) \n(Identified by Additional Cover Pages) \nPage 1"},{"page":7,"startToken":868,"endToken":880,"text":"Revisions to the \nPJM Open Access Transmission Tariff  \n(Marked Format) \nPage 2"},{"page":8,"startToken":880,"endToken":1351,"text":"Definitions – L – M – N \nLarge Load: \n“Large Load” shall have the meaning provided in the Reliability Assurance Agreement. \nLegacy Policy: \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. \nLimited Demand Resource: \n“Limited Demand Resource” shall have the meaning specified in the Reliability Assurance \nAgreement. \nLimited Demand Resource Reliability Target: \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 \nPage 3"},{"page":9,"startToken":1351,"endToken":1827,"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]. \nLimited Resource Constraint: \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. \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. \nList of Approved Contractors: \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. \nLoad Interest: \nPage 4"},{"page":10,"startToken":1827,"endToken":2095,"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. \nLoad Management: \n“Load Management” shall mean a Demand Resource (“DR”) as defined in the Reliability \nAssurance Agreement. \nLoad Management Event: \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.  \nLoad Ratio Share: \n“Load Ratio Share” shall mean the ratio of a Transmission Customer’s Network Load to the \nTransmission Provider’s total load. \nLoad Reduction Event: \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. \nLoad Serving Charging Energy: \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. \nLoad Serving Entity (LSE): \n“Load Serving Entity” or “LSE” shall have the meaning specified in the Reliability Assurance \nAgreement. \nLoad Shedding: \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. \nLocal Upgrades: \nPage 5"},{"page":11,"startToken":2095,"endToken":2490,"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 \nPage 6"},{"page":12,"startToken":2490,"endToken":2760,"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: \n \nPage 7"},{"page":13,"startToken":2760,"endToken":3067,"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: \nPage 8"},{"page":14,"startToken":3067,"endToken":3434,"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.    \n \nPage 9"},{"page":15,"startToken":3434,"endToken":3792,"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:  \nPage 10"},{"page":16,"startToken":3792,"endToken":4079,"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: \nPage 11"},{"page":17,"startToken":4079,"endToken":4526,"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 \nPage 12"},{"page":18,"startToken":4526,"endToken":4989,"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. \nPage 13"},{"page":19,"startToken":4989,"endToken":5290,"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: \nPage 14"},{"page":20,"startToken":5290,"endToken":5583,"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. \n \nPage 15"},{"page":21,"startToken":5583,"endToken":5919,"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: \nPage 16"},{"page":22,"startToken":5919,"endToken":6386,"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 \nPage 17"},{"page":23,"startToken":6386,"endToken":6720,"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 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. \n \nNodal 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 \nPage 18"},{"page":24,"startToken":6720,"endToken":7045,"text":"(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). \n \nNon-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 \nPage 19"},{"page":25,"startToken":7045,"endToken":7407,"text":"Non-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: \n “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 \nPage 20"},{"page":26,"startToken":7407,"endToken":7623,"text":"“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. \n \nNormal Minimum Generation: \n \n“Normal Minimum Generation” shall mean the lowest output level of a generating resource \nunder normal operating conditions. \n \nPage 21"},{"page":27,"startToken":7623,"endToken":7633,"text":"ATTACHMENT DD-4 \nLARGE LOAD REGISTRY \nFormatted: Font: Bold\nPage 22"},{"page":28,"startToken":7633,"endToken":7637,"text":"I. \n[RESERVED] \n \n \nPage 23"},{"page":29,"startToken":7637,"endToken":7695,"text":"III. \nRESPONSBILITIES OF ELECTRIC DISTRIBUTORS \n \nElectric Distributors shall coordinate with the Office of the Interconnection in developing and \nmaintaining the Large Load Registry by providing the Office of the Interconnection any \ninformation or data the Electric Distributor believes appropriate to facilitate an accurate Large \nLoad Registry, including applicable state or RERRA retail tariff or contractual obligations. \n \nPage 24"},{"page":30,"startToken":7695,"endToken":7723,"text":"II.\nRESPONSBILITIES OF THE OFFICE OF THE INTERCONNECTION\nThe Office of the Interconnection shall maintain the Large Load Registry, pursuant to Reliability \nAssurance Agreement, Schedule 11. \nPage 25"},{"page":31,"startToken":7723,"endToken":7734,"text":"Revisions to the \nPJM Reliability Assurance Agreement  \n(Marked Format) \nPage 26"},{"page":32,"startToken":7734,"endToken":8148,"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 \nPage 27"},{"page":33,"startToken":8148,"endToken":8545,"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 \nPage 28"},{"page":34,"startToken":8545,"endToken":9034,"text":"consent has been demonstrated to the satisfaction of the Office of the Interconnection; provided, \nhowever, that Behind The Meter Generation does not include (i) at any time, any portion of such \ngenerating unit’s capacity that is designated as a Generation Capacity Resource or DER Capacity \nAggregation Resource or (ii) in any hour, any portion of the output of such generating unit that is \nsold to another entity for consumption at another electrical location or into the PJM Interchange \nEnergy Market. \n \n \nBlack Start Capability: \n \n \n“Black Start Capability” shall mean the ability of a generating unit or station to go from a \nshutdown condition to an operating condition and start delivering power without assistance from \nthe power system. \n \n \nCapacity Emergency Transfer Objective (CETO): \n \n \n“Capacity Emergency Transfer Objective” or “CETO” shall mean, through the 2024/2025 \nDelivery Year, the amount of electric energy that a given area must be able to import in order to \nremain within a loss of load expectation of one event in 25 years when the area is experiencing a \nlocalized capacity emergency, as determined in accordance with the PJM Manuals.  Without \nlimiting the foregoing, CETO shall be, for Delivery Years through 2024/2025, calculated based \nin part on EFORD determined in accordance with Reliability Assurance Agreement, Schedule 5, \nParagraph C. Beginning with the 2025/2026 Delivery Year, CETO shall mean the amount of \nelectric energy that a given area must be able to import in order to satisfy a normalized expected \nunserved energy for the area that is equal to forty percent of the normalized expected unserved \nenergy for the RTO when at the annual reliability criteria, where normalized expected unserved \nenergy is the expected unserved energy (for the area or RTO, as appropriate) divided by  the \nforecasted annual energy (for the area or RTO, as appropriate), when the area is experiencing a \nlocalized capacity emergency, as determined in accordance with the PJM Manuals. \n \n \nCapacity Emergency Transfer Limit (CETL): \n \n \nCapacity Emergency Transfer Limit” or “CETL” shall mean the capability of the transmission \nsystem to support deliveries of electric energy to a given area experiencing a localized capacity \nemergency as determined in accordance with the PJM Manuals. \n \n \nCapacity Import Limit: \n \nFor any Delivery Year up to and including the 2019/2020 Delivery Year, “Capacity Import \nLimit” shall mean, (a) for the PJM Region, (1) the maximum megawatt quantity of external \nGeneration Capacity Resources that PJM determines for each Delivery Year, through appropriate \nmodeling and the application of engineering judgment, the transmission system can receive, in \naggregate at the interface of the PJM Region with all external balancing authority areas and \ndeliver to load in the PJM Region under capacity emergency conditions without violating \napplicable reliability criteria on any bulk electric system facility of 100kV or greater, internal or \nexternal to the PJM Region, that has an electrically significant response to transfers on such \ninterface, minus (2) the then-applicable Capacity Benefit Margin; and (b) for certain source \nPage 29"},{"page":35,"startToken":9034,"endToken":9650,"text":"zones identified in the PJM manuals as groupings of one or more balancing authority areas, (1) \nthe maximum megawatt quantity of external Generation Capacity Resources that PJM \ndetermines the transmission system can receive at the interface of the PJM Region with each \nsuch source zone and deliver to load in the PJM Region under capacity emergency conditions \nwithout violating applicable reliability criteria on any bulk electric system facility of 100kV or \ngreater, internal or external to the PJM Region, that has an electrically significant response to \ntransfers on such interface, minus the then-applicable Capacity Benefit Margin times (2) the ratio \nof the maximum import quantity from each such source zone divided by the PJM total maximum \nimport quantity.  As more fully set forth in the PJM Manuals, PJM shall make such \ndetermination based on the latest peak load forecast for the studied period, the same computer \nsimulation model of loads, generation and transmission topography employed in the \ndetermination of Capacity Emergency Transfer Limit for such Delivery Year, including external \nfacilities from an industry standard model of the loads, generation, and transmission topography \nof the Eastern Interconnection under peak conditions.  PJM shall specify in the PJM Manuals the \nareas and minimum distribution factors for identifying monitored bulk electric system facilities \nthat have an electrically significant response to such transfers on the PJM interface.  Employing \nsuch tools, PJM shall model increased power transfers from external areas into PJM to determine \nthe transfer level at which one or more reliability criteria is violated on any monitored bulk \nelectric system facilities that have an electrically significant response to such transfers.  For the \nPJM Region Capacity Import Limit, PJM shall optimize transfers from other source areas not \nexperiencing any reliability criteria violations as appropriate to increase the Capacity Import \nLimit.  The aggregate megawatt quantity of transfers into PJM at the point where any increase in \ntransfers on the interface would violate reliability criteria will establish the Capacity Import \nLimit.  Notwithstanding the foregoing, a Capacity Resource located outside the PJM Region \nshall not be subject to the Capacity Import Limit if the Capacity Market Seller seeks an \nexception thereto by demonstrating to PJM, by no later than five (5) business days prior to the \ncommencement of the offer period for the relevant RPM Auction, that such resource meets all of \nthe following requirements: \n(i)  \nit has, at the time such exception is requested, met all applicable requirements to \nbe pseudo-tied into the PJM Region, or the Capacity Market Seller has committed in writing that \nit will meet such requirements, unless prevented from doing so by circumstances beyond the \ncontrol of the Capacity Market Seller, prior to the relevant Delivery Year; \n \n(ii)  \nat the time such exception is requested, it has long-term firm transmission service \nconfirmed on the complete transmission path from such resource into PJM; and \n \n(iii) \nit is, by written commitment of the Capacity Market Seller, subject to the same \nobligations imposed on Generation Capacity Resources located in the PJM Region by Tariff, \nAttachment DD, section 6.6 to offer their capacity into RPM Auctions; provided, however, that \n(a) the total megawatt quantity of all exceptions granted hereunder for a Delivery Year, plus the \nCapacity Import Limit for the applicable interface determined for such Delivery Year, may not \nexceed the total megawatt quantity of Network External Designated Transmission Service on \nsuch interface that PJM has confirmed for such Delivery Year; and (b) if granting a qualified \nexception would result in a violation of the rule in clause (a), PJM shall grant the requested \nexception but reduce the Capacity Import Limit by the quantity necessary to ensure that the total \nquantity of Network External Designated Transmission Service is not exceeded. \nPage 30"},{"page":36,"startToken":9650,"endToken":10054,"text":"Capacity Only Option: \n \n“Capacity Only Option” shall mean participation in Emergency Load Response Program or Pre-\nEmergency Program which allows, pursuant to Tariff, Attachment DD and as applicable, a \ncapacity payment for the ability to reduce load during a pre-emergency or emergency event. \n \nCapacity Performance Resource: \n \n“Capacity Performance Resource” shall have the same meaning as in Tariff, Attachment DD. \n \nCapacity Resources: \n \n \n“Capacity Resources” shall mean megawatts of (i) net capacity from Existing Generation \nCapacity Resources or Planned Generation Capacity Resources meeting the requirements of the \nReliability Assurance Agreement, Schedules 9 and Reliability Assurance Agreement, Schedule \n10 that are or will be owned by or contracted to a Party and that are or will be committed to \nsatisfy that Party's obligations under the Reliability Assurance Agreement, or to satisfy the \nreliability requirements of the PJM Region, for a Delivery Year; (ii) net capacity from Existing \nGeneration Capacity Resources or Planned Generation Capacity Resources not owned or \ncontracted for by a Party which are accredited to the PJM Region pursuant to the procedures set \nforth in such Schedules 9 and 10; or (iii)  load reduction capability provided by Demand \nResources or Energy Efficiency Resources that are accredited to the PJM Region pursuant to the \nprocedures set forth in the Reliability Assurance Agreement, Schedule 6; or (iv) generation and \nload reduction capability provided by a DER Capacity Aggregation Resource, pursuant to the \nprocedures set forth in the Reliability Assurance Agreement, Schedule 6.2 and the PJM Manuals. \n \n \nCapacity Resource Provider: \n \n“Capacity Resource Provider” shall mean a Member that (1) owns, or has the contractual \nauthority to control the output of, a Generation Capacity Resource, that has not transferred such \nauthority to another entity; (2) or a DER Aggregator that has a contractual relationship to use a \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource. \n \nCapacity Storage Resource Class: \n \n“Capacity Storage Resource Class” shall mean the ELCC Classes specified in Schedules 9.1 and \n9.2, section B of this Agreement, each of which is composed of (1) Capacity Storage Resources \nwith the same specified characteristic duration of 4, 6, 8, and 10 hours or; (2) storage device \nComponent DER. The characteristic duration of an Energy Storage Resource Class is the ratio of \nthe modeled MWh energy storage capability of members of the class to the modeled MW power \ncapability of members of the class. \n \nCapacity Transfer Right: \n \n \nPage 31"},{"page":37,"startToken":10054,"endToken":10373,"text":"“Capacity Transfer Right” shall have the meaning specified in Tariff, Attachment DD. \n \nCoal Class: \n \n \n“Coal Class” shall mean an ELCC Class consisting of Unlimited Resources primarily \nfueled by coal. \n \nCombination Resource: \n \n“Combination Resource” shall mean a Generation Capacity Resource, or a generation \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource, that has a component that has the characteristics of a Limited Duration \nResource combined with (i) a component that has the characteristics of an Unlimited Resource or \n(ii) a component that has the characteristics of a Variable Resource. \n \nCompliance Aggregation Area (CAA): \n \n“Compliance Aggregation Area” or “CAA” shall have the same meaning as in the Tariff. \n \nComplex Hybrid Class: \n \n“Complex Hybrid Class” shall mean an ELCC Class composed of Combination Resources that \ncombine three or more components, whereby one component is a class of Limited Duration \nResource, and the other components are different Variable Resource classes, and such \nCombination Resources cannot be included in any other Combination Resource class. A resource \nthat is a member of a Complex Hybrid Class has a single Point Of Interconnection, unless the \nresource is controlled in an integrated fashion, is at a single site, and is approved by PJM to be \nconsidered a single resource in accordance with the PJM Manuals. \n \nConsolidated Transmission Owners Agreement, PJM Transmission Owners Agreement or \nTransmission Owners Agreement: \n \n \n“Consolidated Transmission Owners Agreement,” “PJM Transmission Owners Agreement” or \n“Transmission Owners Agreement” shall mean that certain Consolidated Transmission Owners \nAgreement, dated as of December 15, 2005, by and among the Transmission Owners and by and \nbetween the Transmission Owners and PJM Interconnection, L.L.C. on file with the \nCommission, as amended from time to time. \n \n \nControl Area: \n \n“Control Area” shall mean an electric power system or combination of electric power systems \nbounded by interconnection metering and telemetry to which a common generation control \nscheme is applied in order to: \n \n \nPage 32"},{"page":38,"startToken":10373,"endToken":10694,"text":"(a) \nmatch the power output of the generators within the electric power system(s) and \nenergy purchased from entities outside the electric power system(s), with the load within the \nelectric power system(s); \n \n \n \n(b) \nmaintain scheduled interchange with other Control Areas, within the limits of \nGood Utility Practice; \n \n \n \n (c) \nmaintain the frequency of the electric power system(s) within reasonable limits in \naccordance with Good Utility Practice and the criteria of NERC and each Applicable Regional \nEntity; \n \n \n \n(d) \nmaintain power flows on transmission facilities within appropriate limits to \npreserve reliability; and \n \n \n \n(e) \nprovide sufficient generating capacity to maintain operating reserves in \naccordance with Good Utility Practice. \n \n \nDaily Unforced Capacity Obligation: \n \n \n“Daily Unforced Capacity Obligation” shall mean the capacity obligation of a Load Serving \nEntity during the Delivery Year, determined in accordance with the Reliability Assurance \nAgreement, Schedule 8 or, as to an FRR Entity, in the Reliability Assurance Agreement, \nSchedule 8.1. \n \n \nDelivery Year: \n \n \n“Delivery Year” shall mean a Planning Period for which a Capacity Resource is committed \npursuant to the auction procedures specified in Tariff, Attachment DD or pursuant to an FRR \nCapacity Plan under RAA, Schedule 8.1. \n \n \nDemand Resource (DR): \n \n \n“Demand Resource” or “DR” shall mean a Limited Demand Resource, Extended Summer \nDemand Resource, Annual Demand Resource, Base Capacity Demand Resource or Summer-\nPeriod Demand Resource with a demonstrated capability to provide a reduction in demand or \notherwise control load in accordance with the requirements of RAA, Schedule 6 that offers and \nthat clears load reduction capability in a Base Residual Auction or Incremental Auction or that is \ncommitted through an FRR Capacity Plan.   \n \nDemand Resource Factor or DR Factor: \n \n \n“Demand Resource Factor” or “DR Factor” shall mean, for Delivery Years through May 31, \n2018, that factor approved from time to time by the PJM Board used to determine the unforced \ncapacity value of a Demand Resource in accordance with Reliability Assurance Agreement, \nSchedule 6 \n \nPage 33"},{"page":39,"startToken":10694,"endToken":11032,"text":"Demand Resource Officer Certification Form: \n \n“Demand Resource Officer Certification Form” shall mean a certification as to an intended \nDemand Resource Sell Offer, in accordance with Reliability Assurance Agreement, Schedule 6 \nand Reliability Assurance Agreement, Schedule 8.1 and the PJM Manuals. \n \n \nDemand Resource Registration: \n \n“Demand Resource Registration” shall mean a registration in the Full Program Option or \nCapacity Only Option of the Emergency or Pre-Emergency Load Resource Program in \naccordance with Tariff, Attachment K-Appendix, section 8. \n \nDemand Resource Sell Offer Plan: \n \n“Demand Resource Sell Offer Plan” shall mean the plan required by Reliability Assurance \nAgreement, Schedule 6 and Reliability Assurance Agreement, Schedule 8.1 in support of an \nintended offer of Demand Resources in an RPM Auction, or an intended inclusion of Demand \nResources in an FRR Capacity Plan. \n \nDiesel Utility Class: \n \n\"Diesel Utility Class\" shall mean an ELCC Class consisting of Unlimited Resources of the diesel \ntechnology type that is not primarily fueled by landfill gas. \n \nDER Aggregator Officer Certification Form:  \n \n“DER Aggregator Officer Certification Form” shall mean a DER Aggregator’s certification as to \nan intended DER Capacity Aggregation Resource Sell Offer, in accordance with Reliability \nAssurance Agreement, Schedule 6.2 and Reliability Assurance Agreement, Schedule 8.1 and the \nPJM Manuals. \n \nDER Capacity Aggregation Resource Sell Offer Plan:  \n \n“DER Capacity Aggregation Resource Sell Offer Plan” shall mean the plan required by \nReliability Assurance Agreement, Schedule 6.2 and Reliability Assurance Agreement, Schedule \n8.1 in support of an intended offer of a DER Capacity Aggregation Resource in an RPM \nAuction, or an intended inclusion of a DER Capacity Aggregation Resource in an FRR Capacity \nPlan. \n \nEffective Nameplate Capacity: \n \n“Effective Nameplate Capacity” shall mean (i) for each Variable Resource and Combination \nResource that is a Generation Capacity Resource, the resource’s Maximum Facility Output (or, \nfor a Co-Located Resource, the applicable share of the Mixed Technology Facility’s Maximum \nFacility Output); (ii) for each Variable Resource and Combination Resource, that is an individual \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nPage 34"},{"page":40,"startToken":11032,"endToken":11438,"text":"Aggregation Resource, the device’s maximum energy production capability, as defined by the \nresource’s state interconnection agreement; or (iii) for each Limited Duration Resource, the \nsustained level of output that the device can provide and maintain over a continuous period, \nwhereby the duration of that continuous period matches the characteristic duration of the \ncorresponding ELCC Class, with consideration given to ambient conditions expected to exist at \nthe time of PJM system peak load, to the extent that such conditions impact such resource’s \ncapability, not to exceed the Maximum Facility Output (or, for a Co-Located Resource, the \napplicable share of the Mixed Technology Facility’s Maximum Facility Output).  For the \n2025/2026 Delivery Year and subsequent Delivery Years, the Effective Nameplate Capacity of \neach Limited Duration Resource shall not exceed the greater of the Capacity Interconnection \nRights of such Limited Duration Resource, or the transitional system capability as limited by the \ntransitional resource MW ceiling as defined in the PJM Manuals, awarded for the applicable \nDelivery Year. \n \nEffective UCAP: \n \n“Effective UCAP” shall mean a unit of measure that represents the capacity product transacted in \nthe Reliability Pricing Model and included in FRR Capacity Plans.  One megawatt of Effective \nUCAP has the same capacity value of one megawatt of Unforced Capacity. \n \nELCC Class: \n \n“ELCC Class” shall mean a defined group of ELCC Resources that share a common set of \noperational characteristics and for which effective load carrying capability analysis, as set forth \nin RAA, Schedules 9.1 and 9.2, will establish a unique ELCC Class UCAP and corresponding \nELCC Class Rating(s). ELCC Classes shall be defined in the Schedules 9.1 and 9.2, section B of \nthis Agreement.  Members of an ELCC Class shall share a common method of calculating the \nELCC Resource Performance Adjustment, provided that the individual ELCC Resource \nPerformance Adjustment values will generally differ among ELCC Resources. \n \nELCC Class Rating: \n \n“ELCC Class Rating” shall mean the rating factor, based on effective load carrying capability \nanalysis, that applies to ELCC Resources that are members of an ELCC Class as part of the \ncalculation of their Accredited UCAP. \n \nELCC Class UCAP: \n \n“ELCC Class UCAP” shall mean the aggregate Effective UCAP all modeled ELCC Resources in \na given ELCC Class are capable of providing in a given Delivery Year.  \n \nELCC Portfolio UCAP: \n \n“ELCC Portfolio UCAP” shall mean the aggregate Effective UCAP that all modeled ELCC \nResources are capable of providing in a given Delivery Year. \n \nPage 35"},{"page":41,"startToken":11438,"endToken":11841,"text":"ELCC Resource: \n \n“ELCC Resource” shall mean a Component DER within a DER Aggregation Resource that is \nlinked to a DER Capacity Aggregation Resource, a Generation Capacity Resource or a Demand \nResource. \n \nELCC Resource Performance Adjustment: \n \n“ELCC Resource Performance Adjustment” shall mean the performance of a specific ELCC \nResource relative to the aggregate performance of the ELCC Class to which it belongs as further \ndescribed in RAA, Schedule 9.1, section F and RAA, Schedule 9.2, section D. \n \nElectric Cooperative: \n \n \n“Electric Cooperative” shall mean an entity owned in cooperative form by its customers that is \nengaged in the generation, transmission, and/or distribution of electric energy. \n \n \nElectric Distributor: \n \n \n“Electric Distributor” shall mean a Member that 1) owns or leases with rights equivalent to \nownership of electric distribution facilities that are used to provide electric distribution service to \nelectric load within the PJM Region; or 2) is a generation and transmission cooperative or a joint \nmunicipal agency that has a member that owns electric distribution facilities used to provide \nelectric distribution service to electric load within the PJM Region. \n \n \nEmergency: \n \n \n“Emergency” shall mean (i) an abnormal system condition requiring manual or automatic action \nto maintain system frequency, or to prevent loss of firm load, equipment damage, or tripping of \nsystem elements that could adversely affect the reliability of an electric system or the safety of \npersons or property; or (ii) a fuel shortage requiring departure from normal operating procedures \nin order to minimize the use of such scarce fuel; or (iii) a condition that requires implementation \nof emergency procedures as defined in the PJM Manuals. \n \n \nEnd-Use Customer: \n \n \n“End-Use Customer” shall mean a Member that is a retail end-user of electricity within the \nPJM Region.  For purposes of Members Committee sector classification, a Member that is a \nretail end-user that owns generation may qualify as an End-Use customer if:  (1) the average \nphysical unforced capacity owned by the Member and its affiliates in the PJM region over the \nfive Planning Periods immediately preceding the relevant Planning Period does not exceed the \naverage PJM capacity obligation for the Member and its affiliates over the same time period; or \n(2) the average energy produced by the Member and its affiliates within the PJM region over the \nfive Planning Periods immediately preceding the relevant Planning Period does not exceed the \naverage energy consumed by that Member and its affiliates within the PJM region over the same \nPage 36"},{"page":42,"startToken":11841,"endToken":12256,"text":"time period.  The foregoing notwithstanding, taking retail service may not be sufficient to qualify \na Member as an End-Use Customer. \n \n \n \nEnergy Efficiency Resource: \n \n \n“Energy Efficiency Resource” shall mean a project, including installation of more efficient \ndevices or equipment or implementation of more efficient processes or systems, meeting the \nrequirements of RAA, Schedule 6 and exceeding then-current building codes, appliance \nstandards, or other relevant standards, designed to achieve a continuous (during the periods \ndescribed in Reliability Assurance Agreement, Schedule 6 and the PJM Manuals) reduction in \nelectric energy consumption that is not reflected in the peak load forecast prepared for the \nDelivery Year for which the Energy Efficiency Resource is proposed, and that is fully \nimplemented at all times during such Delivery Year, without any requirement of notice, dispatch, \nor operator intervention.  Annual Energy Efficiency Resources, Base Capacity Energy Efficiency \nResources and Summer-Period Energy Efficiency Resources are types of Energy Efficiency \nResources. \n \nExigent Water Storage: \n \n“Exigent Water Storage” shall mean water stored in the pondage or reservoir of a hydropower \nresource which is not typically available during normal operating conditions (as those conditions \nare described in the relevant FERC hydropower license), but which can be drawn upon during \nemergency conditions (as described in the FERC hydropower license), including in order to \navoid a load shed.  In an effective load carrying capability analysis, exigent storage capability \nfrom an upstream hydro facility can be considered relative to a downstream hydro facility by \nassessing cascading storage and flows. \n \nExisting Demand Resource: \n \n“Existing Demand Resource” shall mean a Demand Resource for which the Demand Resource \nProvider has identified existing end-use customer sites that are registered for the current Delivery \nYear with PJM (even if not registered by such Demand Resource Provider) and that the Demand \nResource Provider reasonably expects to have under a contract to reduce load based on PJM \ndispatch instructions by the start of the Delivery Year for which such resource is offered. \n \nExisting DER Capacity Aggregation Resource: \n \n“Existing DER Capacity Aggregation Resource” shall mean a DER Capacity Aggregation \nResource for which the DER Aggregator has identified existing Component DER that are \nregistered in a DER Capacity Aggregation Resource for the current Delivery Year with PJM \n(even if not registered by such DER Aggregator) and that the DER Aggregator reasonably \nexpects to have under a contract to generate or reduce load based on PJM dispatch instructions \nby the start of the Delivery Year for which such DER Capacity Aggregation Resource is offered. \n \nExisting Generation Capacity Resource: \nPage 37"},{"page":43,"startToken":12256,"endToken":12697,"text":"“Existing Generation Capacity Resource” shall mean, for purposes of the must-offer requirement \nand mitigation of offers for any RPM Auction for a Delivery Year, a Generation Capacity \nResource that, as of the date on which bidding commences for such auction: (a) is in service; or \n(b) is not yet in service, but has cleared any RPM Auction for any prior Delivery Year.  A \nGeneration Capacity Resource shall be deemed to be in service if interconnection service has \never commenced (for resources located in the PJM Region), or if it is physically and electrically \ninterconnected to an external Control Area and is in full commercial operation (for resources not \nlocated in the PJM Region).  The additional megawatts of a Generation Capacity Resource that is \nbeing, or has been, modified to increase the number of megawatts of available installed capacity \nthereof shall not be deemed to be an Existing Generation Capacity Resource until such time as \nthose megawatts (a) are in service; or (b) are not yet in service, but have cleared any RPM \nAuction for any prior Delivery Year. \n \nExtended Summer Demand Resource: \n \n“Extended Summer Demand Resource” shall mean, for Delivery Years through May 31, 2018, \nand for FRR Capacity Plans Delivery Years through May 31, 2019, a resource that is placed \nunder the direction of the Office of the Interconnection and that will be available June through \nOctober and the following May, and will be available for an unlimited number of interruptions \nduring such months by the Office of the Interconnection, and will be capable of maintaining each \nsuch interruption for at least a 10-hour duration between the hours of 10:00AM to 10:00PM \nEastern Prevailing Time. The Extended Summer Demand Resource must be available June \nthrough October and the following May in the corresponding Delivery Year to be offered for sale \nor Self-Supplied in an RPM Auction, or included as an Extended Summer Demand Resource in \nan FRR Capacity Plan for the corresponding Delivery Year.   \n \n \nFacilities Study Agreement: \n \n \n“Facilities Study Agreement” shall have the same meaning as in Tariff, Part VI, section 206. \n \n \n \nFERC or Commission: \n \n \n“FERC” or “Commission” shall mean the Federal Energy Regulatory Commission or any \nsuccessor federal agency, commission or department exercising jurisdiction over the Tariff, \nOperating Agreement and Reliability Assurance Agreement. \n \n \nFirm Point-To-Point Transmission Service: \n \n \n“Firm Point-To-Point Transmission Service” shall have the meaning specified in the Tariff. \n \n \nFirm Service Level: \n \n“Firm Service Level” or “FSL” of Price Responsive Demand shall mean the level, determined at \na PRD Substation level, to which Price Responsive Demand shall be reduced during the Delivery \nYear when the Locational Marginal Price exceeds the price associated with such Price \nPage 38"},{"page":44,"startToken":12697,"endToken":13033,"text":"Responsive Demand identified by the PRD Provider in its PRD Plan. “Firm Service Level” or \n“FSL” of Demand Resource shall mean the pre-determined level to which an end-use customer’s \nload shall be reduced, upon notification from the Curtailment Service Provider’s market \noperations center or its agent. \n \nFirm Transmission Service: \n \n \n“Firm Transmission Service” shall mean transmission service that is intended to be available at \nall times to the maximum extent practicable, subject to an Emergency, an unanticipated failure of \na facility, or other event beyond the control of the owner or operator of the facility or the Office \nof the Interconnection. \n \n \nFixed Resource Requirement Alternative or FRR Alternative: \n \n \n“Fixed Resource Requirement Alternative” or “FRR Alternative” shall mean an alternative \nmethod for a Party to satisfy its obligation to provide Unforced Capacity hereunder, as set forth \nin the Reliability Assurance Agreement, Schedule 8.1. \n \nFixed-Tilt Solar Class: \n \n“Fixed-Tilt Solar Class” shall mean an ELCC Class consisting of Variable Resources that \nproduce electrical energy with solar panels that are primarily mounted in a fixed orientation. \n \n \nForecast Pool Requirement: \n \n \n“Forecast Pool Requirement” or “FPR” shall mean the amount equal to one plus the unforced \nreserve margin (stated as a decimal number) for the PJM Region required pursuant to this \nReliability Assurance Agreement, as approved by the PJM Board pursuant to Reliability \nAssurance Agreement, Schedule 4.1. \n \n \nFRR Capacity Plan or FRR Plan: \n \n \n“FRR Capacity Plan” or “FRR Plan” shall mean a long-term plan for the commitment of \nCapacity Resources and Price Responsive Demand to satisfy the capacity obligations of a Party \nthat has elected the FRR Alternative, as more fully set forth in the Reliability Assurance \nAgreement, Schedule 8.1. \n \n \nFRR Entity: \n \n \n“FRR Entity” shall mean, for the duration of such election, a Party that has elected the FRR \nAlternative hereunder. \n \n \nFRR Service Area: \n \n \n“FRR Service Area” shall mean (a) the service territory of an IOU as recognized by state law, \nrule or order; (b) the service area of a Public Power Entity or Electric Cooperative as recognized \nPage 39"},{"page":45,"startToken":13033,"endToken":13464,"text":"by franchise or other state law, rule, or order; or (c) a separately identifiable geographic area that \nis: (i) bounded by wholesale metering, or similar appropriate multi-site aggregate metering, that \nis visible to, and regularly reported to, the Office of the Interconnection, or that is visible to, and \nregularly reported to an Electric Distributor and such Electric Distributor agrees to aggregate the \nload data from such meters for such FRR Service Area and regularly report such aggregated \ninformation, by FRR Service Area, to the Office of the Interconnection; and (ii) for which the \nFRR Entity has or assumes the obligation to provide capacity for all load (including load growth) \nwithin such area.  In the event that the service obligations of an Electric Cooperative or Public \nPower Entity are not defined by geographic boundaries but by physical connections to a defined \nset of customers, the FRR Service Area in such circumstances shall be defined as all customers \nphysically connected to transmission or distribution facilities of such Electric Cooperative or \nPublic Power Entity within an area bounded by appropriate wholesale aggregate metering as \ndescribed above.   \n \n \nFull Program Option: \n \n“Full Program Option” shall mean participation in Emergency Load Response Program or Pre-\nEmergency Program which allows, pursuant to Tariff, Attachment DD and as applicable, (i) an \nenergy payment for load reductions during a pre-emergency or emergency event, and (ii) a \ncapacity payment for the ability to reduce load during a pre-emergency or emergency event. \n \nFull Requirements Service: \n \n \n“Full Requirements Service” shall mean wholesale service to supply all of the power needs of a \nLoad Serving Entity to serve end-users within the PJM Region that are not satisfied by its own \ngenerating facilities. \n \nGas Combined Cycle Class: \n \n“Gas Combined Cycle Class” shall mean an ELCC Class consisting of Unlimited Resources of \nthe combined cycle technology type that is primarily fueled by natural gas, but does not meet the \nrequirements to be included in the Gas Combined Cycle Dual Fuel Class. \n \nGas Combined Cycle Dual Fuel Class: \n \n“Gas Combined Cycle Dual Fuel Class” shall mean an ELCC Class consisting of Unlimited \nResources of the combined cycle technology type that is primarily fueled by natural gas, and that \nattests that it has the capability to start independently using onsite sources and operate \nindependently on alternate onsite fuel source(s) up to its maximum capacity level during the \nwinter season of the applicable Delivery Year in which it is providing capacity, and capable of \noperating on the alternate fuel for two 16-hour periods over two consecutive days at its \nmaximum capacity level.  \n \nGas Combustion Turbine Class: \n \nPage 40"},{"page":46,"startToken":13464,"endToken":13944,"text":"“Gas Combustion Turbine Class” shall mean an ELCC Class consisting of Unlimited Resources \nof the combustion turbine technology type that is primarily fueled by natural gas, but does not \nmeet the requirements to be included in the Gas Combustion Turbine Dual Fuel Class. \n \nGas Combustion Turbine Dual Fuel Class: \n \n“Gas Combustion Turbine Dual Fuel Class” shall mean an ELCC Class consisting of Unlimited \nResources of the combustion turbine technology type that is primarily fueled by natural gas, and \nattests that it has the capability to start independently using onsite sources and operate \nindependently on alternate onsite fuel source(s) up to its maximum capacity level during the \nwinter season of the applicable Delivery Year in which it is providing capacity, and capable of \noperating on the alternate fuel for two 16-hour periods over two consecutive days at its \nmaximum capacity level. \n \n \nGeneration Capacity Resource: \n \n \n“Generation Capacity Resource” shall mean a Generating Facility, or the contractual right to \ncapacity from a specified Generating Facility, that meets the requirements of RAA, Schedule 9 \nand RAA, Schedule 10, and, for Generating Facilities that are committed to an FRR Capacity \nPlan, that meets the requirements of RAA, Schedule 8.1.  A Generation Capacity Resource may \nbe an Existing Generation Capacity Resource or a Planned Generation Capacity Resource.  \n \nGeneration Owner: \n \n \n“Generation Owner” shall mean a Member that owns or leases with rights equivalent to \nownership, or otherwise controls and operates one or more operating generation resources \nlocated in the PJM Region.  The foregoing notwithstanding, for a planned generation resource to \nqualify a Member as a Generation Owner, such resource shall have cleared an RPM auction, and \nfor Energy Resources, the resource shall have a FERC-jurisdictional interconnection agreement \nor wholesale market participation agreement within PJM.   Purchasing all or a portion of the \noutput of a generation resource shall not be sufficient to qualify a Member as a Generation \nOwner.  For purposes of Members Committee sector classification, a Member that is primarily a \nretail end-user of electricity that owns generation may qualify as a Generation Owner if:  (1) the \ngeneration resource is the subject of a FERC-jurisdictional interconnection agreement or \nwholesale market participation agreement within PJM; (2) the average physical unforced \ncapacity owned by the Member and its affiliates over the five Planning Periods immediately \npreceding the relevant Planning Period exceeds the average PJM capacity obligation of the \nMember and its affiliates over the same time period; and (3) the average energy produced by the \nMember and its affiliates within PJM over the five Planning Periods immediately preceding the \nrelevant Planning Period exceeds the average energy consumed by the Member and its affiliates \nwithin PJM over the same time period. \n \n \nGenerator Forced Outage: \n \n \n“Generator Forced Outage” shall mean an immediate reduction in output or capacity or removal \nfrom service, in whole or in part, of a generating unit by reason of an Emergency or threatened \nPage 41"},{"page":47,"startToken":13944,"endToken":14397,"text":"Emergency, unanticipated failure, or other cause beyond the control of the owner or operator of \nthe facility, as specified in the relevant portions of the PJM Manuals.  A reduction in output or \nremoval from service of a generating unit in response to changes in market conditions shall not \nconstitute a Generator Forced Outage. \n \n \nGenerator Maintenance Outage: \n \n \n“Generator Maintenance Outage” shall mean the scheduled removal from service, in whole or in \npart, of a generating unit in order to perform repairs on specific components of the facility, if \nremoval of the facility qualifies as a maintenance outage pursuant to the PJM Manuals. \n \n \nGenerator Planned Outage: \n \n \n“Generator Planned Outage” shall mean the scheduled removal from service, in whole or in part, \nof a generating unit for inspection, maintenance or repair with the approval of the Office of the \nInterconnection in accordance with the PJM Manuals. \n \n \nGood Utility Practice: \n \n \n“Good Utility Practice” shall mean any of the practices, methods and acts engaged in or \napproved by a significant portion of the electric utility industry during the relevant time period, \nor any of the practices, methods and acts which, in the exercise of reasonable judgment in light \nof the facts known at the time the decision was made, could have been expected to accomplish \nthe desired result at a reasonable cost consistent with good business practices, reliability, safety \nand expedition.  Good Utility Practice is not intended to be limited to the optimum practice, \nmethod, or act to the exclusion of all others, but rather is intended to include acceptable \npractices, methods, or acts generally accepted in the region; including those practices required by \nFederal Power Act Section 215(a)(4).  \n \n \nHybrid Resource Class: \n \n“Hybrid Resource Class” shall mean the ELCC Classes specified in RAA Schedules 9.1 and 9.2 \nSection B.  Each Hybrid Resource Class has a specified combination of two components, \nwhereby, absent being part of a Combination Resource, the individual components would be in a \nCapacity Storage Resource Class, a Variable Resource Class or would be an Unlimited \nResource.  A resource that is a member of a Hybrid Resource Class has a single Point Of \nInterconnection, unless the resource is controlled in an integrated fashion, is at a single site, and \nis approved by PJM to be considered a single resource in accordance with the PJM Manuals. \n \nHydropower With Non-Pumped Storage: \n \n“Hydropower With Non-Pumped Storage” shall mean a hydropower facility that can capture and \nstore incoming stream flow, without use of pumps, in pondage or a reservoir, and the Generation \nOwner has the ability, within the constraints available in the applicable operating license, to exert \nmaterial control over the quantity of stored water and output of the facility throughout an \nOperating Day. \nPage 42"},{"page":48,"startToken":14397,"endToken":14723,"text":"Hydropower With Non-Pumped Storage Class: \n \n“Hydropower With Non-Pumped Storage Class” shall mean an ELCC Class consisting of \nCombination Resources that are Hydropower With Non-Pumped Storage resources. \n \nIncremental Auction: \n \n \n“Incremental Auction” shall mean any of several auctions conducted for a Delivery Year after \nthe Base Residual Auction for such Delivery Year and before the first day of such Delivery Year, \nincluding the First Incremental Auction, Second Incremental Auction, Third Incremental \nAuction, or Conditional Incremental Auction.  Incremental Auctions (other than the Conditional \nIncremental Auction), shall be held for the purposes of: \n \n(i) \nallowing Market Sellers that committed Capacity Resources in the Base Residual \nAuction for a Delivery Year, which subsequently are determined to be unavailable \nto deliver the committed Unforced Capacity in such Delivery Year (due to \nresource retirement, resource cancellation or construction delay, resource \nderating, EFORd increase, Accredited UCAP Factor decrease, a decrease in the \nNominated Demand Resource Value of a Planned Demand Resource, delay or \ncancellation of a Qualifying Transmission Upgrade, or similar occurrences) to \nsubmit Buy Bids for replacement Capacity Resources; and  \n \n(ii) \nallowing the Office of the Interconnection to reduce or increase the amount of \ncommitted capacity secured in prior auctions for such Delivery Year if, as a result \nof changed circumstances or expectations since the prior auction(s), there is, \nrespectively, a significant excess or significant deficit of committed capacity for \nsuch Delivery Year, for the PJM Region or for an LDA. \n \n \nIntermittent Hydropower Class: \n \n“Intermittent Hydropower Class” shall mean an ELCC Class consisting of Variable Resources \nthat are run-of-river hydropower generators that must generally pass incoming water and \ntherefore cannot appreciably store water to later increase the output of the facility. Resources in \nthe Intermittent Hydropower Class are not Hydropower with Non-Pumped Storage resources. \n \nIOU: \n \n \n“IOU” shall mean an investor-owned utility with substantial business interest in owning and/or \noperating electric facilities in any two or more of the following three asset categories:  \ngeneration, transmission, distribution. \n \nIntermittent Landfill Gas Class: \n \nPage 43"},{"page":49,"startToken":14723,"endToken":15164,"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: \n \n \nPage 44"},{"page":50,"startToken":15164,"endToken":15477,"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 \nenergy from an identified Generation Capacity Resource located outside the PJM Region, upon \nPage 45"},{"page":51,"startToken":15477,"endToken":15740,"text":"demonstration 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: \n \n \nPage 46"},{"page":52,"startToken":15740,"endToken":16084,"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 \ncharacteristic duration of an Other Limited Duration Class is the maximum period of time \nrepresented in the ELCC model that the resources of the class can run at a stated capability. \nPage 47"},{"page":53,"startToken":16084,"endToken":16473,"text":"Other 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. \n \nPeak Shaving Adjustment:  \nPage 48"},{"page":54,"startToken":16473,"endToken":16768,"text":"“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 \nPJM Manuals: \n \n \n“PJM Manuals” shall mean the instructions, rules, procedures and guidelines established by the \nOffice of the Interconnection for the operation, planning and accounting requirements of the PJM \nRegion. \n \nPJM Region: \n \n \n“PJM Region” shall have the same meaning as provided in the Operating Agreement. \n \n \nPJM Region Installed Reserve Margin: \n \n \n“PJM Region Installed Reserve Margin” shall mean the percent installed reserve margin for the \nPJM Region required pursuant to Reliability Assurance Agreement, Schedule 4.1, as approved \nby the PJM Board. \nPage 49"},{"page":55,"startToken":16768,"endToken":17288,"text":"PJM 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 \nDelivery Year for which such resource is to be committed to satisfy the reliability requirements \nof the PJM Region, and (d) is in full commercial operation prior to the first day of such Delivery \nYear, such that it is sufficient to provide the Installed Capacity set forth in the Sell Offer forming \nthe basis of such resource’s commitment to the PJM Region.  Prior to participation in any Base \nResidual Auction for such Delivery Year, the Capacity Market Seller must demonstrate that it \nhas documentation which is functionally equivalent to an approved Decision Point I submission \nPage 50"},{"page":56,"startToken":17288,"endToken":17924,"text":"under 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 \nwhich a Decision Point II submission is not required, has such other agreement or documentation \nthat is functionally equivalent to an approved Decision Point II submission) has been executed \nprior to the Base Residual Auction for such Delivery Year; and (iv) a Generation Interconnection \nAgreement or Wholesale Market Participation Agreement has been executed prior to any \nIncremental Auction for such Delivery Year in which such resource plans to participate.  For \npurposes of the must-offer requirement and mitigation of offers for any RPM Auction for a \nPage 51"},{"page":57,"startToken":17924,"endToken":18277,"text":"Delivery 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: \n \n“PRD Reservation Price” shall mean an RPM Auction clearing price identified in a PRD Plan for \nPrice Responsive Demand load below which the PRD Provider desires not to commit the \nidentified load as Price Responsive Demand. \n  \nPRD Substation: \n \nPage 52"},{"page":58,"startToken":18277,"endToken":18663,"text":"“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. \n \n \nRelevant Electric Retail Regulatory Authority: \n \n“Relevant Electric Retail Regulatory Authority” or “RERRA” shall have the meaning specified \nin the PJM Operating Agreement. \n \nPage 53"},{"page":59,"startToken":18663,"endToken":19022,"text":"Reliability 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, \nwithout limitation, mandating divestiture of utility-owned generation or structural changes to \nsuch Party’s default service rules that materially affect whether retail choice is economically \nviable. \n \nSteam Class: \n \nPage 54"},{"page":60,"startToken":19022,"endToken":19494,"text":"“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: \n \n \n“Threshold Quantity” shall mean, as to any FRR Entity for any Delivery Year, the sum of (a) the \nUnforced Capacity equivalent (determined using the Pool-Wide Average EFORD through the \n2024/2025 Delivery Year, or pool-wide average Accredited UCAP Factor effective with the \n2025/2026 Delivery Year) of the Installed Reserve Margin for such Delivery Year multiplied by \nthe Preliminary Forecast Peak Load for which such FRR Entity is responsible under its FRR \nPage 55"},{"page":61,"startToken":19494,"endToken":19879,"text":"Capacity 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. \n \nVariable Resource: \n \n“Variable Resource” shall mean a Generation Capacity Resource or a generation Component \nDER within a DER Aggregation Resource that is linked to a DER Capacity Aggregation \nResource, with output that can vary as a function of its energy source, such as wind, solar, run of \nPage 56"},{"page":62,"startToken":19879,"endToken":20282,"text":"river 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. \n \nPage 57"},{"page":63,"startToken":20282,"endToken":20578,"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 \n \n \n \n \n \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 entity bound by the Operating Agreement shall submit, or cause to be \nsubmitted, to the Office of the Interconnection the following information, as may be further \ndescribed in the PJM Manuals, related to each Large Load served by the entity bound by \nthe Operating Agreement: \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 \nPage 58"},{"page":64,"startToken":20578,"endToken":20976,"text":"zone/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; \n• Telemetry specifications; \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 entities bound by the Operating Agreement acknowledge that \ninformation related to the development and maintenance of the Large Load Registry may \nbe obtained by the Office of the Interconnection from Electric Distributors in accordance \nwith the provisions of the Operating 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 entity \nbound by the Operating Agreement, as well as other information provided by, for example, \nElectric Distributors, the Office of the Interconnection shall maintain a registry of all Large \nLoads, and update it periodically.  To the extent such documents, data, or other information \nprovided to the Office of the Interconnection has been designated as confidential by an \nentity bound by the Operating Agreement, Electric Distributor, or other entity supplying \nthe information, the Office of the Interconnection shall maintain the confidentiality of the \ninformation provided under this RAA, Schedule 11, section B consistent with its \nobligations under Operating Agreement, section 18.17.  Information maintained in the \nLarge Load registry may be available to Authorized Commissions, Transmission Owners, \nElectric Distributors, Load Serving Entities, the Market Monitoring Unit, and FERC \nsubject to appropriate data protection safeguards required by Operating Agreement, section \n18.17. \n \nPage 59"},{"page":65,"startToken":20976,"endToken":21191,"text":"(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 entity bound by the Operating Agreement serving or contracted to \nserve a Large Load that is or will be in service prior to June 1, 2027, shall provide the \ninformation required by RAA, Schedule 11.B.1 to the Office of the Interconnection by \nMarch 1, 2027.  \n \n(b) \nEach entity bound by the Operating Agreement serving or contracted to \nserve a Large Load that will be in service on or after June 1, 2027, shall provide the \ninformation required by RAA, Schedule 11.B.1 to the Office of the Interconnection before \nthe in-service date of the Large Load. \n \nEach entity bound by the Operating Agreement shall promptly inform the Office of the \nInterconnection of any change in the information required by RAA, Schedule 11.B.1 with \nrespect to a Large Load served by such entity bound by the Operating Agreement, including \nwhether the entity bound by the Operating Agreement no longer serves the Large Load or \nhas acquired the contractual right to serve a registered Large Load. \nPage 60"},{"page":66,"startToken":21191,"endToken":21214,"text":"Attachment B \nRevisions to the  \nPJM Open Access Transmission Tariff and \nReliability Assurance Agreement \n(Clean Format) \n(Identified by Additional Cover Pages) \nPage 1"},{"page":67,"startToken":21214,"endToken":21226,"text":"Revisions to the \nPJM Open Access Transmission Tariff  \n(Clean Format) \nPage 2"},{"page":68,"startToken":21226,"endToken":21697,"text":"Definitions – L – M – N \nLarge Load: \n“Large Load” shall have the meaning provided in the Reliability Assurance Agreement. \nLegacy Policy: \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. \nLimited Demand Resource: \n“Limited Demand Resource” shall have the meaning specified in the Reliability Assurance \nAgreement. \nLimited Demand Resource Reliability Target: \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 \nPage 3"},{"page":69,"startToken":21697,"endToken":22173,"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]. \nLimited Resource Constraint: \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. \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. \nList of Approved Contractors: \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. \nLoad Interest: \nPage 4"},{"page":70,"startToken":22173,"endToken":22441,"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: \n \nPage 5"},{"page":71,"startToken":22441,"endToken":22836,"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 \nPage 6"},{"page":72,"startToken":22836,"endToken":23106,"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: \n \nPage 7"},{"page":73,"startToken":23106,"endToken":23413,"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: \nPage 8"},{"page":74,"startToken":23413,"endToken":23780,"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.    \n \nPage 9"},{"page":75,"startToken":23780,"endToken":24138,"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:  \nPage 10"},{"page":76,"startToken":24138,"endToken":24425,"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: \nPage 11"},{"page":77,"startToken":24425,"endToken":24872,"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 \nPage 12"},{"page":78,"startToken":24872,"endToken":25335,"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. \nPage 13"},{"page":79,"startToken":25335,"endToken":25636,"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: \nPage 14"},{"page":80,"startToken":25636,"endToken":25929,"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. \n \nPage 15"},{"page":81,"startToken":25929,"endToken":26265,"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: \nPage 16"},{"page":82,"startToken":26265,"endToken":26732,"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 \nPage 17"},{"page":83,"startToken":26732,"endToken":27066,"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. \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. \n \nNodal 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 \nPage 18"},{"page":84,"startToken":27066,"endToken":27391,"text":"(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). \n \nNon-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 \nPage 19"},{"page":85,"startToken":27391,"endToken":27753,"text":"Non-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: \n “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 \nPage 20"},{"page":86,"startToken":27753,"endToken":27969,"text":"“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. \n \nNormal Minimum Generation: \n \n“Normal Minimum Generation” shall mean the lowest output level of a generating resource \nunder normal operating conditions. \n \nPage 21"},{"page":87,"startToken":27969,"endToken":27976,"text":"ATTACHMENT DD-4 \nLARGE LOAD REGISTRY \nPage 22"},{"page":88,"startToken":27976,"endToken":27980,"text":"I. \n[RESERVED] \n \n \nPage 23"},{"page":89,"startToken":27980,"endToken":28038,"text":"III. \nRESPONSBILITIES OF ELECTRIC DISTRIBUTORS \n \nElectric Distributors shall coordinate with the Office of the Interconnection in developing and \nmaintaining the Large Load Registry by providing the Office of the Interconnection any \ninformation or data the Electric Distributor believes appropriate to facilitate an accurate Large \nLoad Registry, including applicable state or RERRA retail tariff or contractual obligations. \n \nPage 24"},{"page":90,"startToken":28038,"endToken":28066,"text":"II. \nRESPONSBILITIES OF THE OFFICE OF THE INTERCONNECTION  \n \nThe Office of the Interconnection shall maintain the Large Load Registry, pursuant to Reliability \nAssurance Agreement, Schedule 11. \nPage 25"},{"page":91,"startToken":28066,"endToken":28077,"text":"Revisions to the \nPJM Reliability Assurance Agreement  \n \n(Clean Format) \n \nPage 26"},{"page":92,"startToken":28077,"endToken":28491,"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 \nPage 27"},{"page":93,"startToken":28491,"endToken":28888,"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 \nPage 28"},{"page":94,"startToken":28888,"endToken":29377,"text":"consent has been demonstrated to the satisfaction of the Office of the Interconnection; provided, \nhowever, that Behind The Meter Generation does not include (i) at any time, any portion of such \ngenerating unit’s capacity that is designated as a Generation Capacity Resource or DER Capacity \nAggregation Resource or (ii) in any hour, any portion of the output of such generating unit that is \nsold to another entity for consumption at another electrical location or into the PJM Interchange \nEnergy Market. \n \n \nBlack Start Capability: \n \n \n“Black Start Capability” shall mean the ability of a generating unit or station to go from a \nshutdown condition to an operating condition and start delivering power without assistance from \nthe power system. \n \n \nCapacity Emergency Transfer Objective (CETO): \n \n \n“Capacity Emergency Transfer Objective” or “CETO” shall mean, through the 2024/2025 \nDelivery Year, the amount of electric energy that a given area must be able to import in order to \nremain within a loss of load expectation of one event in 25 years when the area is experiencing a \nlocalized capacity emergency, as determined in accordance with the PJM Manuals.  Without \nlimiting the foregoing, CETO shall be, for Delivery Years through 2024/2025, calculated based \nin part on EFORD determined in accordance with Reliability Assurance Agreement, Schedule 5, \nParagraph C. Beginning with the 2025/2026 Delivery Year, CETO shall mean the amount of \nelectric energy that a given area must be able to import in order to satisfy a normalized expected \nunserved energy for the area that is equal to forty percent of the normalized expected unserved \nenergy for the RTO when at the annual reliability criteria, where normalized expected unserved \nenergy is the expected unserved energy (for the area or RTO, as appropriate) divided by  the \nforecasted annual energy (for the area or RTO, as appropriate), when the area is experiencing a \nlocalized capacity emergency, as determined in accordance with the PJM Manuals. \n \n \nCapacity Emergency Transfer Limit (CETL): \n \n \nCapacity Emergency Transfer Limit” or “CETL” shall mean the capability of the transmission \nsystem to support deliveries of electric energy to a given area experiencing a localized capacity \nemergency as determined in accordance with the PJM Manuals. \n \n \nCapacity Import Limit: \n \nFor any Delivery Year up to and including the 2019/2020 Delivery Year, “Capacity Import \nLimit” shall mean, (a) for the PJM Region, (1) the maximum megawatt quantity of external \nGeneration Capacity Resources that PJM determines for each Delivery Year, through appropriate \nmodeling and the application of engineering judgment, the transmission system can receive, in \naggregate at the interface of the PJM Region with all external balancing authority areas and \ndeliver to load in the PJM Region under capacity emergency conditions without violating \napplicable reliability criteria on any bulk electric system facility of 100kV or greater, internal or \nexternal to the PJM Region, that has an electrically significant response to transfers on such \ninterface, minus (2) the then-applicable Capacity Benefit Margin; and (b) for certain source \nPage 29"},{"page":95,"startToken":29377,"endToken":29993,"text":"zones identified in the PJM manuals as groupings of one or more balancing authority areas, (1) \nthe maximum megawatt quantity of external Generation Capacity Resources that PJM \ndetermines the transmission system can receive at the interface of the PJM Region with each \nsuch source zone and deliver to load in the PJM Region under capacity emergency conditions \nwithout violating applicable reliability criteria on any bulk electric system facility of 100kV or \ngreater, internal or external to the PJM Region, that has an electrically significant response to \ntransfers on such interface, minus the then-applicable Capacity Benefit Margin times (2) the ratio \nof the maximum import quantity from each such source zone divided by the PJM total maximum \nimport quantity.  As more fully set forth in the PJM Manuals, PJM shall make such \ndetermination based on the latest peak load forecast for the studied period, the same computer \nsimulation model of loads, generation and transmission topography employed in the \ndetermination of Capacity Emergency Transfer Limit for such Delivery Year, including external \nfacilities from an industry standard model of the loads, generation, and transmission topography \nof the Eastern Interconnection under peak conditions.  PJM shall specify in the PJM Manuals the \nareas and minimum distribution factors for identifying monitored bulk electric system facilities \nthat have an electrically significant response to such transfers on the PJM interface.  Employing \nsuch tools, PJM shall model increased power transfers from external areas into PJM to determine \nthe transfer level at which one or more reliability criteria is violated on any monitored bulk \nelectric system facilities that have an electrically significant response to such transfers.  For the \nPJM Region Capacity Import Limit, PJM shall optimize transfers from other source areas not \nexperiencing any reliability criteria violations as appropriate to increase the Capacity Import \nLimit.  The aggregate megawatt quantity of transfers into PJM at the point where any increase in \ntransfers on the interface would violate reliability criteria will establish the Capacity Import \nLimit.  Notwithstanding the foregoing, a Capacity Resource located outside the PJM Region \nshall not be subject to the Capacity Import Limit if the Capacity Market Seller seeks an \nexception thereto by demonstrating to PJM, by no later than five (5) business days prior to the \ncommencement of the offer period for the relevant RPM Auction, that such resource meets all of \nthe following requirements: \n(i)  \nit has, at the time such exception is requested, met all applicable requirements to \nbe pseudo-tied into the PJM Region, or the Capacity Market Seller has committed in writing that \nit will meet such requirements, unless prevented from doing so by circumstances beyond the \ncontrol of the Capacity Market Seller, prior to the relevant Delivery Year; \n \n(ii)  \nat the time such exception is requested, it has long-term firm transmission service \nconfirmed on the complete transmission path from such resource into PJM; and \n \n(iii) \nit is, by written commitment of the Capacity Market Seller, subject to the same \nobligations imposed on Generation Capacity Resources located in the PJM Region by Tariff, \nAttachment DD, section 6.6 to offer their capacity into RPM Auctions; provided, however, that \n(a) the total megawatt quantity of all exceptions granted hereunder for a Delivery Year, plus the \nCapacity Import Limit for the applicable interface determined for such Delivery Year, may not \nexceed the total megawatt quantity of Network External Designated Transmission Service on \nsuch interface that PJM has confirmed for such Delivery Year; and (b) if granting a qualified \nexception would result in a violation of the rule in clause (a), PJM shall grant the requested \nexception but reduce the Capacity Import Limit by the quantity necessary to ensure that the total \nquantity of Network External Designated Transmission Service is not exceeded. \nPage 30"},{"page":96,"startToken":29993,"endToken":30397,"text":"Capacity Only Option: \n \n“Capacity Only Option” shall mean participation in Emergency Load Response Program or Pre-\nEmergency Program which allows, pursuant to Tariff, Attachment DD and as applicable, a \ncapacity payment for the ability to reduce load during a pre-emergency or emergency event. \n \nCapacity Performance Resource: \n \n“Capacity Performance Resource” shall have the same meaning as in Tariff, Attachment DD. \n \nCapacity Resources: \n \n \n“Capacity Resources” shall mean megawatts of (i) net capacity from Existing Generation \nCapacity Resources or Planned Generation Capacity Resources meeting the requirements of the \nReliability Assurance Agreement, Schedules 9 and Reliability Assurance Agreement, Schedule \n10 that are or will be owned by or contracted to a Party and that are or will be committed to \nsatisfy that Party's obligations under the Reliability Assurance Agreement, or to satisfy the \nreliability requirements of the PJM Region, for a Delivery Year; (ii) net capacity from Existing \nGeneration Capacity Resources or Planned Generation Capacity Resources not owned or \ncontracted for by a Party which are accredited to the PJM Region pursuant to the procedures set \nforth in such Schedules 9 and 10; or (iii)  load reduction capability provided by Demand \nResources or Energy Efficiency Resources that are accredited to the PJM Region pursuant to the \nprocedures set forth in the Reliability Assurance Agreement, Schedule 6; or (iv) generation and \nload reduction capability provided by a DER Capacity Aggregation Resource, pursuant to the \nprocedures set forth in the Reliability Assurance Agreement, Schedule 6.2 and the PJM Manuals. \n \n \nCapacity Resource Provider: \n \n“Capacity Resource Provider” shall mean a Member that (1) owns, or has the contractual \nauthority to control the output of, a Generation Capacity Resource, that has not transferred such \nauthority to another entity; (2) or a DER Aggregator that has a contractual relationship to use a \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource. \n \nCapacity Storage Resource Class: \n \n“Capacity Storage Resource Class” shall mean the ELCC Classes specified in Schedules 9.1 and \n9.2, section B of this Agreement, each of which is composed of (1) Capacity Storage Resources \nwith the same specified characteristic duration of 4, 6, 8, and 10 hours or; (2) storage device \nComponent DER. The characteristic duration of an Energy Storage Resource Class is the ratio of \nthe modeled MWh energy storage capability of members of the class to the modeled MW power \ncapability of members of the class. \n \nCapacity Transfer Right: \n \n \nPage 31"},{"page":97,"startToken":30397,"endToken":30716,"text":"“Capacity Transfer Right” shall have the meaning specified in Tariff, Attachment DD. \n \nCoal Class: \n \n \n“Coal Class” shall mean an ELCC Class consisting of Unlimited Resources primarily \nfueled by coal. \n \nCombination Resource: \n \n“Combination Resource” shall mean a Generation Capacity Resource, or a generation \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nAggregation Resource, that has a component that has the characteristics of a Limited Duration \nResource combined with (i) a component that has the characteristics of an Unlimited Resource or \n(ii) a component that has the characteristics of a Variable Resource. \n \nCompliance Aggregation Area (CAA): \n \n“Compliance Aggregation Area” or “CAA” shall have the same meaning as in the Tariff. \n \nComplex Hybrid Class: \n \n“Complex Hybrid Class” shall mean an ELCC Class composed of Combination Resources that \ncombine three or more components, whereby one component is a class of Limited Duration \nResource, and the other components are different Variable Resource classes, and such \nCombination Resources cannot be included in any other Combination Resource class. A resource \nthat is a member of a Complex Hybrid Class has a single Point Of Interconnection, unless the \nresource is controlled in an integrated fashion, is at a single site, and is approved by PJM to be \nconsidered a single resource in accordance with the PJM Manuals. \n \nConsolidated Transmission Owners Agreement, PJM Transmission Owners Agreement or \nTransmission Owners Agreement: \n \n \n“Consolidated Transmission Owners Agreement,” “PJM Transmission Owners Agreement” or \n“Transmission Owners Agreement” shall mean that certain Consolidated Transmission Owners \nAgreement, dated as of December 15, 2005, by and among the Transmission Owners and by and \nbetween the Transmission Owners and PJM Interconnection, L.L.C. on file with the \nCommission, as amended from time to time. \n \n \nControl Area: \n \n“Control Area” shall mean an electric power system or combination of electric power systems \nbounded by interconnection metering and telemetry to which a common generation control \nscheme is applied in order to: \n \n \nPage 32"},{"page":98,"startToken":30716,"endToken":31037,"text":"(a) \nmatch the power output of the generators within the electric power system(s) and \nenergy purchased from entities outside the electric power system(s), with the load within the \nelectric power system(s); \n \n \n \n(b) \nmaintain scheduled interchange with other Control Areas, within the limits of \nGood Utility Practice; \n \n \n \n (c) \nmaintain the frequency of the electric power system(s) within reasonable limits in \naccordance with Good Utility Practice and the criteria of NERC and each Applicable Regional \nEntity; \n \n \n \n(d) \nmaintain power flows on transmission facilities within appropriate limits to \npreserve reliability; and \n \n \n \n(e) \nprovide sufficient generating capacity to maintain operating reserves in \naccordance with Good Utility Practice. \n \n \nDaily Unforced Capacity Obligation: \n \n \n“Daily Unforced Capacity Obligation” shall mean the capacity obligation of a Load Serving \nEntity during the Delivery Year, determined in accordance with the Reliability Assurance \nAgreement, Schedule 8 or, as to an FRR Entity, in the Reliability Assurance Agreement, \nSchedule 8.1. \n \n \nDelivery Year: \n \n \n“Delivery Year” shall mean a Planning Period for which a Capacity Resource is committed \npursuant to the auction procedures specified in Tariff, Attachment DD or pursuant to an FRR \nCapacity Plan under RAA, Schedule 8.1. \n \n \nDemand Resource (DR): \n \n \n“Demand Resource” or “DR” shall mean a Limited Demand Resource, Extended Summer \nDemand Resource, Annual Demand Resource, Base Capacity Demand Resource or Summer-\nPeriod Demand Resource with a demonstrated capability to provide a reduction in demand or \notherwise control load in accordance with the requirements of RAA, Schedule 6 that offers and \nthat clears load reduction capability in a Base Residual Auction or Incremental Auction or that is \ncommitted through an FRR Capacity Plan.   \n \nDemand Resource Factor or DR Factor: \n \n \n“Demand Resource Factor” or “DR Factor” shall mean, for Delivery Years through May 31, \n2018, that factor approved from time to time by the PJM Board used to determine the unforced \ncapacity value of a Demand Resource in accordance with Reliability Assurance Agreement, \nSchedule 6 \n \nPage 33"},{"page":99,"startToken":31037,"endToken":31375,"text":"Demand Resource Officer Certification Form: \n \n“Demand Resource Officer Certification Form” shall mean a certification as to an intended \nDemand Resource Sell Offer, in accordance with Reliability Assurance Agreement, Schedule 6 \nand Reliability Assurance Agreement, Schedule 8.1 and the PJM Manuals. \n \n \nDemand Resource Registration: \n \n“Demand Resource Registration” shall mean a registration in the Full Program Option or \nCapacity Only Option of the Emergency or Pre-Emergency Load Resource Program in \naccordance with Tariff, Attachment K-Appendix, section 8. \n \nDemand Resource Sell Offer Plan: \n \n“Demand Resource Sell Offer Plan” shall mean the plan required by Reliability Assurance \nAgreement, Schedule 6 and Reliability Assurance Agreement, Schedule 8.1 in support of an \nintended offer of Demand Resources in an RPM Auction, or an intended inclusion of Demand \nResources in an FRR Capacity Plan. \n \nDiesel Utility Class: \n \n\"Diesel Utility Class\" shall mean an ELCC Class consisting of Unlimited Resources of the diesel \ntechnology type that is not primarily fueled by landfill gas. \n \nDER Aggregator Officer Certification Form:  \n \n“DER Aggregator Officer Certification Form” shall mean a DER Aggregator’s certification as to \nan intended DER Capacity Aggregation Resource Sell Offer, in accordance with Reliability \nAssurance Agreement, Schedule 6.2 and Reliability Assurance Agreement, Schedule 8.1 and the \nPJM Manuals. \n \nDER Capacity Aggregation Resource Sell Offer Plan:  \n \n“DER Capacity Aggregation Resource Sell Offer Plan” shall mean the plan required by \nReliability Assurance Agreement, Schedule 6.2 and Reliability Assurance Agreement, Schedule \n8.1 in support of an intended offer of a DER Capacity Aggregation Resource in an RPM \nAuction, or an intended inclusion of a DER Capacity Aggregation Resource in an FRR Capacity \nPlan. \n \nEffective Nameplate Capacity: \n \n“Effective Nameplate Capacity” shall mean (i) for each Variable Resource and Combination \nResource that is a Generation Capacity Resource, the resource’s Maximum Facility Output (or, \nfor a Co-Located Resource, the applicable share of the Mixed Technology Facility’s Maximum \nFacility Output); (ii) for each Variable Resource and Combination Resource, that is an individual \nComponent DER within a DER Aggregation Resource that is linked to a DER Capacity \nPage 34"},{"page":100,"startToken":31375,"endToken":31781,"text":"Aggregation Resource, the device’s maximum energy production capability, as defined by the \nresource’s state interconnection agreement; or (iii) for each Limited Duration Resource, the \nsustained level of output that the device can provide and maintain over a continuous period, \nwhereby the duration of that continuous period matches the characteristic duration of the \ncorresponding ELCC Class, with consideration given to ambient conditions expected to exist at \nthe time of PJM system peak load, to the extent that such conditions impact such resource’s \ncapability, not to exceed the Maximum Facility Output (or, for a Co-Located Resource, the \napplicable share of the Mixed Technology Facility’s Maximum Facility Output).  For the \n2025/2026 Delivery Year and subsequent Delivery Years, the Effective Nameplate Capacity of \neach Limited Duration Resource shall not exceed the greater of the Capacity Interconnection \nRights of such Limited Duration Resource, or the transitional system capability as limited by the \ntransitional resource MW ceiling as defined in the PJM Manuals, awarded for the applicable \nDelivery Year. \n \nEffective UCAP: \n \n“Effective UCAP” shall mean a unit of measure that represents the capacity product transacted in \nthe Reliability Pricing Model and included in FRR Capacity Plans.  One megawatt of Effective \nUCAP has the same capacity value of one megawatt of Unforced Capacity. \n \nELCC Class: \n \n“ELCC Class” shall mean a defined group of ELCC Resources that share a common set of \noperational characteristics and for which effective load carrying capability analysis, as set forth \nin RAA, Schedules 9.1 and 9.2, will establish a unique ELCC Class UCAP and corresponding \nELCC Class Rating(s). ELCC Classes shall be defined in the Schedules 9.1 and 9.2, section B of \nthis Agreement.  Members of an ELCC Class shall share a common method of calculating the \nELCC Resource Performance Adjustment, provided that the individual ELCC Resource \nPerformance Adjustment values will generally differ among ELCC Resources. \n \nELCC Class Rating: \n \n“ELCC Class Rating” shall mean the rating factor, based on effective load carrying capability \nanalysis, that applies to ELCC Resources that are members of an ELCC Class as part of the \ncalculation of their Accredited UCAP. \n \nELCC Class UCAP: \n \n“ELCC Class UCAP” shall mean the aggregate Effective UCAP all modeled ELCC Resources in \na given ELCC Class are capable of providing in a given Delivery Year.  \n \nELCC Portfolio UCAP: \n \n“ELCC Portfolio UCAP” shall mean the aggregate Effective UCAP that all modeled ELCC \nResources are capable of providing in a given Delivery Year. \n \nPage 35"},{"page":101,"startToken":31781,"endToken":32184,"text":"ELCC Resource: \n \n“ELCC Resource” shall mean a Component DER within a DER Aggregation Resource that is \nlinked to a DER Capacity Aggregation Resource, a Generation Capacity Resource or a Demand \nResource. \n \nELCC Resource Performance Adjustment: \n \n“ELCC Resource Performance Adjustment” shall mean the performance of a specific ELCC \nResource relative to the aggregate performance of the ELCC Class to which it belongs as further \ndescribed in RAA, Schedule 9.1, section F and RAA, Schedule 9.2, section D. \n \nElectric Cooperative: \n \n \n“Electric Cooperative” shall mean an entity owned in cooperative form by its customers that is \nengaged in the generation, transmission, and/or distribution of electric energy. \n \n \nElectric Distributor: \n \n \n“Electric Distributor” shall mean a Member that 1) owns or leases with rights equivalent to \nownership of electric distribution facilities that are used to provide electric distribution service to \nelectric load within the PJM Region; or 2) is a generation and transmission cooperative or a joint \nmunicipal agency that has a member that owns electric distribution facilities used to provide \nelectric distribution service to electric load within the PJM Region. \n \n \nEmergency: \n \n \n“Emergency” shall mean (i) an abnormal system condition requiring manual or automatic action \nto maintain system frequency, or to prevent loss of firm load, equipment damage, or tripping of \nsystem elements that could adversely affect the reliability of an electric system or the safety of \npersons or property; or (ii) a fuel shortage requiring departure from normal operating procedures \nin order to minimize the use of such scarce fuel; or (iii) a condition that requires implementation \nof emergency procedures as defined in the PJM Manuals. \n \n \nEnd-Use Customer: \n \n \n“End-Use Customer” shall mean a Member that is a retail end-user of electricity within the \nPJM Region.  For purposes of Members Committee sector classification, a Member that is a \nretail end-user that owns generation may qualify as an End-Use customer if:  (1) the average \nphysical unforced capacity owned by the Member and its affiliates in the PJM region over the \nfive Planning Periods immediately preceding the relevant Planning Period does not exceed the \naverage PJM capacity obligation for the Member and its affiliates over the same time period; or \n(2) the average energy produced by the Member and its affiliates within the PJM region over the \nfive Planning Periods immediately preceding the relevant Planning Period does not exceed the \naverage energy consumed by that Member and its affiliates within the PJM region over the same \nPage 36"},{"page":102,"startToken":32184,"endToken":32599,"text":"time period.  The foregoing notwithstanding, taking retail service may not be sufficient to qualify \na Member as an End-Use Customer. \n \n \n \nEnergy Efficiency Resource: \n \n \n“Energy Efficiency Resource” shall mean a project, including installation of more efficient \ndevices or equipment or implementation of more efficient processes or systems, meeting the \nrequirements of RAA, Schedule 6 and exceeding then-current building codes, appliance \nstandards, or other relevant standards, designed to achieve a continuous (during the periods \ndescribed in Reliability Assurance Agreement, Schedule 6 and the PJM Manuals) reduction in \nelectric energy consumption that is not reflected in the peak load forecast prepared for the \nDelivery Year for which the Energy Efficiency Resource is proposed, and that is fully \nimplemented at all times during such Delivery Year, without any requirement of notice, dispatch, \nor operator intervention.  Annual Energy Efficiency Resources, Base Capacity Energy Efficiency \nResources and Summer-Period Energy Efficiency Resources are types of Energy Efficiency \nResources. \n \nExigent Water Storage: \n \n“Exigent Water Storage” shall mean water stored in the pondage or reservoir of a hydropower \nresource which is not typically available during normal operating conditions (as those conditions \nare described in the relevant FERC hydropower license), but which can be drawn upon during \nemergency conditions (as described in the FERC hydropower license), including in order to \navoid a load shed.  In an effective load carrying capability analysis, exigent storage capability \nfrom an upstream hydro facility can be considered relative to a downstream hydro facility by \nassessing cascading storage and flows. \n \nExisting Demand Resource: \n \n“Existing Demand Resource” shall mean a Demand Resource for which the Demand Resource \nProvider has identified existing end-use customer sites that are registered for the current Delivery \nYear with PJM (even if not registered by such Demand Resource Provider) and that the Demand \nResource Provider reasonably expects to have under a contract to reduce load based on PJM \ndispatch instructions by the start of the Delivery Year for which such resource is offered. \n \nExisting DER Capacity Aggregation Resource: \n \n“Existing DER Capacity Aggregation Resource” shall mean a DER Capacity Aggregation \nResource for which the DER Aggregator has identified existing Component DER that are \nregistered in a DER Capacity Aggregation Resource for the current Delivery Year with PJM \n(even if not registered by such DER Aggregator) and that the DER Aggregator reasonably \nexpects to have under a contract to generate or reduce load based on PJM dispatch instructions \nby the start of the Delivery Year for which such DER Capacity Aggregation Resource is offered. \n \nExisting Generation Capacity Resource: \nPage 37"},{"page":103,"startToken":32599,"endToken":33040,"text":"“Existing Generation Capacity Resource” shall mean, for purposes of the must-offer requirement \nand mitigation of offers for any RPM Auction for a Delivery Year, a Generation Capacity \nResource that, as of the date on which bidding commences for such auction: (a) is in service; or \n(b) is not yet in service, but has cleared any RPM Auction for any prior Delivery Year.  A \nGeneration Capacity Resource shall be deemed to be in service if interconnection service has \never commenced (for resources located in the PJM Region), or if it is physically and electrically \ninterconnected to an external Control Area and is in full commercial operation (for resources not \nlocated in the PJM Region).  The additional megawatts of a Generation Capacity Resource that is \nbeing, or has been, modified to increase the number of megawatts of available installed capacity \nthereof shall not be deemed to be an Existing Generation Capacity Resource until such time as \nthose megawatts (a) are in service; or (b) are not yet in service, but have cleared any RPM \nAuction for any prior Delivery Year. \n \nExtended Summer Demand Resource: \n \n“Extended Summer Demand Resource” shall mean, for Delivery Years through May 31, 2018, \nand for FRR Capacity Plans Delivery Years through May 31, 2019, a resource that is placed \nunder the direction of the Office of the Interconnection and that will be available June through \nOctober and the following May, and will be available for an unlimited number of interruptions \nduring such months by the Office of the Interconnection, and will be capable of maintaining each \nsuch interruption for at least a 10-hour duration between the hours of 10:00AM to 10:00PM \nEastern Prevailing Time. The Extended Summer Demand Resource must be available June \nthrough October and the following May in the corresponding Delivery Year to be offered for sale \nor Self-Supplied in an RPM Auction, or included as an Extended Summer Demand Resource in \nan FRR Capacity Plan for the corresponding Delivery Year.   \n \n \nFacilities Study Agreement: \n \n \n“Facilities Study Agreement” shall have the same meaning as in Tariff, Part VI, section 206. \n \n \n \nFERC or Commission: \n \n \n“FERC” or “Commission” shall mean the Federal Energy Regulatory Commission or any \nsuccessor federal agency, commission or department exercising jurisdiction over the Tariff, \nOperating Agreement and Reliability Assurance Agreement. \n \n \nFirm Point-To-Point Transmission Service: \n \n \n“Firm Point-To-Point Transmission Service” shall have the meaning specified in the Tariff. \n \n \nFirm Service Level: \n \n“Firm Service Level” or “FSL” of Price Responsive Demand shall mean the level, determined at \na PRD Substation level, to which Price Responsive Demand shall be reduced during the Delivery \nYear when the Locational Marginal Price exceeds the price associated with such Price \nPage 38"},{"page":104,"startToken":33040,"endToken":33376,"text":"Responsive Demand identified by the PRD Provider in its PRD Plan. “Firm Service Level” or \n“FSL” of Demand Resource shall mean the pre-determined level to which an end-use customer’s \nload shall be reduced, upon notification from the Curtailment Service Provider’s market \noperations center or its agent. \n \nFirm Transmission Service: \n \n \n“Firm Transmission Service” shall mean transmission service that is intended to be available at \nall times to the maximum extent practicable, subject to an Emergency, an unanticipated failure of \na facility, or other event beyond the control of the owner or operator of the facility or the Office \nof the Interconnection. \n \n \nFixed Resource Requirement Alternative or FRR Alternative: \n \n \n“Fixed Resource Requirement Alternative” or “FRR Alternative” shall mean an alternative \nmethod for a Party to satisfy its obligation to provide Unforced Capacity hereunder, as set forth \nin the Reliability Assurance Agreement, Schedule 8.1. \n \nFixed-Tilt Solar Class: \n \n“Fixed-Tilt Solar Class” shall mean an ELCC Class consisting of Variable Resources that \nproduce electrical energy with solar panels that are primarily mounted in a fixed orientation. \n \n \nForecast Pool Requirement: \n \n \n“Forecast Pool Requirement” or “FPR” shall mean the amount equal to one plus the unforced \nreserve margin (stated as a decimal number) for the PJM Region required pursuant to this \nReliability Assurance Agreement, as approved by the PJM Board pursuant to Reliability \nAssurance Agreement, Schedule 4.1. \n \n \nFRR Capacity Plan or FRR Plan: \n \n \n“FRR Capacity Plan” or “FRR Plan” shall mean a long-term plan for the commitment of \nCapacity Resources and Price Responsive Demand to satisfy the capacity obligations of a Party \nthat has elected the FRR Alternative, as more fully set forth in the Reliability Assurance \nAgreement, Schedule 8.1. \n \n \nFRR Entity: \n \n \n“FRR Entity” shall mean, for the duration of such election, a Party that has elected the FRR \nAlternative hereunder. \n \n \nFRR Service Area: \n \n \n“FRR Service Area” shall mean (a) the service territory of an IOU as recognized by state law, \nrule or order; (b) the service area of a Public Power Entity or Electric Cooperative as recognized \nPage 39"},{"page":105,"startToken":33376,"endToken":33807,"text":"by franchise or other state law, rule, or order; or (c) a separately identifiable geographic area that \nis: (i) bounded by wholesale metering, or similar appropriate multi-site aggregate metering, that \nis visible to, and regularly reported to, the Office of the Interconnection, or that is visible to, and \nregularly reported to an Electric Distributor and such Electric Distributor agrees to aggregate the \nload data from such meters for such FRR Service Area and regularly report such aggregated \ninformation, by FRR Service Area, to the Office of the Interconnection; and (ii) for which the \nFRR Entity has or assumes the obligation to provide capacity for all load (including load growth) \nwithin such area.  In the event that the service obligations of an Electric Cooperative or Public \nPower Entity are not defined by geographic boundaries but by physical connections to a defined \nset of customers, the FRR Service Area in such circumstances shall be defined as all customers \nphysically connected to transmission or distribution facilities of such Electric Cooperative or \nPublic Power Entity within an area bounded by appropriate wholesale aggregate metering as \ndescribed above.   \n \n \nFull Program Option: \n \n“Full Program Option” shall mean participation in Emergency Load Response Program or Pre-\nEmergency Program which allows, pursuant to Tariff, Attachment DD and as applicable, (i) an \nenergy payment for load reductions during a pre-emergency or emergency event, and (ii) a \ncapacity payment for the ability to reduce load during a pre-emergency or emergency event. \n \nFull Requirements Service: \n \n \n“Full Requirements Service” shall mean wholesale service to supply all of the power needs of a \nLoad Serving Entity to serve end-users within the PJM Region that are not satisfied by its own \ngenerating facilities. \n \nGas Combined Cycle Class: \n \n“Gas Combined Cycle Class” shall mean an ELCC Class consisting of Unlimited Resources of \nthe combined cycle technology type that is primarily fueled by natural gas, but does not meet the \nrequirements to be included in the Gas Combined Cycle Dual Fuel Class. \n \nGas Combined Cycle Dual Fuel Class: \n \n“Gas Combined Cycle Dual Fuel Class” shall mean an ELCC Class consisting of Unlimited \nResources of the combined cycle technology type that is primarily fueled by natural gas, and that \nattests that it has the capability to start independently using onsite sources and operate \nindependently on alternate onsite fuel source(s) up to its maximum capacity level during the \nwinter season of the applicable Delivery Year in which it is providing capacity, and capable of \noperating on the alternate fuel for two 16-hour periods over two consecutive days at its \nmaximum capacity level.  \n \nGas Combustion Turbine Class: \n \nPage 40"},{"page":106,"startToken":33807,"endToken":34287,"text":"“Gas Combustion Turbine Class” shall mean an ELCC Class consisting of Unlimited Resources \nof the combustion turbine technology type that is primarily fueled by natural gas, but does not \nmeet the requirements to be included in the Gas Combustion Turbine Dual Fuel Class. \n \nGas Combustion Turbine Dual Fuel Class: \n \n“Gas Combustion Turbine Dual Fuel Class” shall mean an ELCC Class consisting of Unlimited \nResources of the combustion turbine technology type that is primarily fueled by natural gas, and \nattests that it has the capability to start independently using onsite sources and operate \nindependently on alternate onsite fuel source(s) up to its maximum capacity level during the \nwinter season of the applicable Delivery Year in which it is providing capacity, and capable of \noperating on the alternate fuel for two 16-hour periods over two consecutive days at its \nmaximum capacity level. \n \n \nGeneration Capacity Resource: \n \n \n“Generation Capacity Resource” shall mean a Generating Facility, or the contractual right to \ncapacity from a specified Generating Facility, that meets the requirements of RAA, Schedule 9 \nand RAA, Schedule 10, and, for Generating Facilities that are committed to an FRR Capacity \nPlan, that meets the requirements of RAA, Schedule 8.1.  A Generation Capacity Resource may \nbe an Existing Generation Capacity Resource or a Planned Generation Capacity Resource.  \n \nGeneration Owner: \n \n \n“Generation Owner” shall mean a Member that owns or leases with rights equivalent to \nownership, or otherwise controls and operates one or more operating generation resources \nlocated in the PJM Region.  The foregoing notwithstanding, for a planned generation resource to \nqualify a Member as a Generation Owner, such resource shall have cleared an RPM auction, and \nfor Energy Resources, the resource shall have a FERC-jurisdictional interconnection agreement \nor wholesale market participation agreement within PJM.   Purchasing all or a portion of the \noutput of a generation resource shall not be sufficient to qualify a Member as a Generation \nOwner.  For purposes of Members Committee sector classification, a Member that is primarily a \nretail end-user of electricity that owns generation may qualify as a Generation Owner if:  (1) the \ngeneration resource is the subject of a FERC-jurisdictional interconnection agreement or \nwholesale market participation agreement within PJM; (2) the average physical unforced \ncapacity owned by the Member and its affiliates over the five Planning Periods immediately \npreceding the relevant Planning Period exceeds the average PJM capacity obligation of the \nMember and its affiliates over the same time period; and (3) the average energy produced by the \nMember and its affiliates within PJM over the five Planning Periods immediately preceding the \nrelevant Planning Period exceeds the average energy consumed by the Member and its affiliates \nwithin PJM over the same time period. \n \n \nGenerator Forced Outage: \n \n \n“Generator Forced Outage” shall mean an immediate reduction in output or capacity or removal \nfrom service, in whole or in part, of a generating unit by reason of an Emergency or threatened \nPage 41"},{"page":107,"startToken":34287,"endToken":34740,"text":"Emergency, unanticipated failure, or other cause beyond the control of the owner or operator of \nthe facility, as specified in the relevant portions of the PJM Manuals.  A reduction in output or \nremoval from service of a generating unit in response to changes in market conditions shall not \nconstitute a Generator Forced Outage. \n \n \nGenerator Maintenance Outage: \n \n \n“Generator Maintenance Outage” shall mean the scheduled removal from service, in whole or in \npart, of a generating unit in order to perform repairs on specific components of the facility, if \nremoval of the facility qualifies as a maintenance outage pursuant to the PJM Manuals. \n \n \nGenerator Planned Outage: \n \n \n“Generator Planned Outage” shall mean the scheduled removal from service, in whole or in part, \nof a generating unit for inspection, maintenance or repair with the approval of the Office of the \nInterconnection in accordance with the PJM Manuals. \n \n \nGood Utility Practice: \n \n \n“Good Utility Practice” shall mean any of the practices, methods and acts engaged in or \napproved by a significant portion of the electric utility industry during the relevant time period, \nor any of the practices, methods and acts which, in the exercise of reasonable judgment in light \nof the facts known at the time the decision was made, could have been expected to accomplish \nthe desired result at a reasonable cost consistent with good business practices, reliability, safety \nand expedition.  Good Utility Practice is not intended to be limited to the optimum practice, \nmethod, or act to the exclusion of all others, but rather is intended to include acceptable \npractices, methods, or acts generally accepted in the region; including those practices required by \nFederal Power Act Section 215(a)(4).  \n \n \nHybrid Resource Class: \n \n“Hybrid Resource Class” shall mean the ELCC Classes specified in RAA Schedules 9.1 and 9.2 \nSection B.  Each Hybrid Resource Class has a specified combination of two components, \nwhereby, absent being part of a Combination Resource, the individual components would be in a \nCapacity Storage Resource Class, a Variable Resource Class or would be an Unlimited \nResource.  A resource that is a member of a Hybrid Resource Class has a single Point Of \nInterconnection, unless the resource is controlled in an integrated fashion, is at a single site, and \nis approved by PJM to be considered a single resource in accordance with the PJM Manuals. \n \nHydropower With Non-Pumped Storage: \n \n“Hydropower With Non-Pumped Storage” shall mean a hydropower facility that can capture and \nstore incoming stream flow, without use of pumps, in pondage or a reservoir, and the Generation \nOwner has the ability, within the constraints available in the applicable operating license, to exert \nmaterial control over the quantity of stored water and output of the facility throughout an \nOperating Day. \nPage 42"},{"page":108,"startToken":34740,"endToken":35066,"text":"Hydropower With Non-Pumped Storage Class: \n \n“Hydropower With Non-Pumped Storage Class” shall mean an ELCC Class consisting of \nCombination Resources that are Hydropower With Non-Pumped Storage resources. \n \nIncremental Auction: \n \n \n“Incremental Auction” shall mean any of several auctions conducted for a Delivery Year after \nthe Base Residual Auction for such Delivery Year and before the first day of such Delivery Year, \nincluding the First Incremental Auction, Second Incremental Auction, Third Incremental \nAuction, or Conditional Incremental Auction.  Incremental Auctions (other than the Conditional \nIncremental Auction), shall be held for the purposes of: \n \n(i) \nallowing Market Sellers that committed Capacity Resources in the Base Residual \nAuction for a Delivery Year, which subsequently are determined to be unavailable \nto deliver the committed Unforced Capacity in such Delivery Year (due to \nresource retirement, resource cancellation or construction delay, resource \nderating, EFORd increase, Accredited UCAP Factor decrease, a decrease in the \nNominated Demand Resource Value of a Planned Demand Resource, delay or \ncancellation of a Qualifying Transmission Upgrade, or similar occurrences) to \nsubmit Buy Bids for replacement Capacity Resources; and  \n \n(ii) \nallowing the Office of the Interconnection to reduce or increase the amount of \ncommitted capacity secured in prior auctions for such Delivery Year if, as a result \nof changed circumstances or expectations since the prior auction(s), there is, \nrespectively, a significant excess or significant deficit of committed capacity for \nsuch Delivery Year, for the PJM Region or for an LDA. \n \n \nIntermittent Hydropower Class: \n \n“Intermittent Hydropower Class” shall mean an ELCC Class consisting of Variable Resources \nthat are run-of-river hydropower generators that must generally pass incoming water and \ntherefore cannot appreciably store water to later increase the output of the facility. Resources in \nthe Intermittent Hydropower Class are not Hydropower with Non-Pumped Storage resources. \n \nIOU: \n \n \n“IOU” shall mean an investor-owned utility with substantial business interest in owning and/or \noperating electric facilities in any two or more of the following three asset categories:  \ngeneration, transmission, distribution. \n \nIntermittent Landfill Gas Class: \n \nPage 43"},{"page":109,"startToken":35066,"endToken":35507,"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: \n \n \nPage 44"},{"page":110,"startToken":35507,"endToken":35820,"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 \nenergy from an identified Generation Capacity Resource located outside the PJM Region, upon \nPage 45"},{"page":111,"startToken":35820,"endToken":36083,"text":"demonstration 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: \n \n \nPage 46"},{"page":112,"startToken":36083,"endToken":36427,"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 \ncharacteristic duration of an Other Limited Duration Class is the maximum period of time \nrepresented in the ELCC model that the resources of the class can run at a stated capability. \nPage 47"},{"page":113,"startToken":36427,"endToken":36816,"text":"Other 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. \n \nPeak Shaving Adjustment:  \nPage 48"},{"page":114,"startToken":36816,"endToken":37111,"text":"“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 \nPJM Manuals: \n \n \n“PJM Manuals” shall mean the instructions, rules, procedures and guidelines established by the \nOffice of the Interconnection for the operation, planning and accounting requirements of the PJM \nRegion. \n \nPJM Region: \n \n \n“PJM Region” shall have the same meaning as provided in the Operating Agreement. \n \n \nPJM Region Installed Reserve Margin: \n \n \n“PJM Region Installed Reserve Margin” shall mean the percent installed reserve margin for the \nPJM Region required pursuant to Reliability Assurance Agreement, Schedule 4.1, as approved \nby the PJM Board. \nPage 49"},{"page":115,"startToken":37111,"endToken":37631,"text":"PJM 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 \nDelivery Year for which such resource is to be committed to satisfy the reliability requirements \nof the PJM Region, and (d) is in full commercial operation prior to the first day of such Delivery \nYear, such that it is sufficient to provide the Installed Capacity set forth in the Sell Offer forming \nthe basis of such resource’s commitment to the PJM Region.  Prior to participation in any Base \nResidual Auction for such Delivery Year, the Capacity Market Seller must demonstrate that it \nhas documentation which is functionally equivalent to an approved Decision Point I submission \nPage 50"},{"page":116,"startToken":37631,"endToken":38267,"text":"under 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 \nwhich a Decision Point II submission is not required, has such other agreement or documentation \nthat is functionally equivalent to an approved Decision Point II submission) has been executed \nprior to the Base Residual Auction for such Delivery Year; and (iv) a Generation Interconnection \nAgreement or Wholesale Market Participation Agreement has been executed prior to any \nIncremental Auction for such Delivery Year in which such resource plans to participate.  For \npurposes of the must-offer requirement and mitigation of offers for any RPM Auction for a \nPage 51"},{"page":117,"startToken":38267,"endToken":38620,"text":"Delivery 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: \n \n“PRD Reservation Price” shall mean an RPM Auction clearing price identified in a PRD Plan for \nPrice Responsive Demand load below which the PRD Provider desires not to commit the \nidentified load as Price Responsive Demand. \n  \nPRD Substation: \n \nPage 52"},{"page":118,"startToken":38620,"endToken":39006,"text":"“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. \n \n \nRelevant Electric Retail Regulatory Authority: \n \n“Relevant Electric Retail Regulatory Authority” or “RERRA” shall have the meaning specified \nin the PJM Operating Agreement. \n \nPage 53"},{"page":119,"startToken":39006,"endToken":39365,"text":"Reliability 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, \nwithout limitation, mandating divestiture of utility-owned generation or structural changes to \nsuch Party’s default service rules that materially affect whether retail choice is economically \nviable. \n \nSteam Class: \n \nPage 54"},{"page":120,"startToken":39365,"endToken":39837,"text":"“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: \n \n \n“Threshold Quantity” shall mean, as to any FRR Entity for any Delivery Year, the sum of (a) the \nUnforced Capacity equivalent (determined using the Pool-Wide Average EFORD through the \n2024/2025 Delivery Year, or pool-wide average Accredited UCAP Factor effective with the \n2025/2026 Delivery Year) of the Installed Reserve Margin for such Delivery Year multiplied by \nthe Preliminary Forecast Peak Load for which such FRR Entity is responsible under its FRR \nPage 55"},{"page":121,"startToken":39837,"endToken":40222,"text":"Capacity 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. \n \nVariable Resource: \n \n“Variable Resource” shall mean a Generation Capacity Resource or a generation Component \nDER within a DER Aggregation Resource that is linked to a DER Capacity Aggregation \nResource, with output that can vary as a function of its energy source, such as wind, solar, run of \nPage 56"},{"page":122,"startToken":40222,"endToken":40625,"text":"river 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. \n \nPage 57"},{"page":123,"startToken":40625,"endToken":40986,"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 entity bound by the Operating Agreement shall submit, or cause to be \nsubmitted, to the Office of the Interconnection the following information, as may be further \ndescribed in the PJM Manuals, related to each Large Load served by the entity bound by \nthe Operating Agreement: \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); \nPage 58"},{"page":124,"startToken":40986,"endToken":41410,"text":"• Peak load quantity (MW) and ramp schedule, if applicable; \n• Telemetry specifications; \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 entities bound by the Operating Agreement acknowledge that \ninformation related to the development and maintenance of the Large Load Registry may \nbe obtained by the Office of the Interconnection from Electric Distributors in accordance \nwith the provisions of the Operating 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 entity \nbound by the Operating Agreement, as well as other information provided by, for example, \nElectric Distributors, the Office of the Interconnection shall maintain a registry of all Large \nLoads, and update it periodically.  To the extent such documents, data, or other information \nprovided to the Office of the Interconnection has been designated as confidential by an \nentity bound by the Operating Agreement, Electric Distributor, or other entity supplying \nthe information, the Office of the Interconnection shall maintain the confidentiality of the \ninformation provided under this RAA, Schedule 11, section B consistent with its \nobligations under Operating Agreement, section 18.17.  Information maintained in the \nLarge Load registry may be available to Authorized Commissions, Transmission Owners, \nElectric Distributors, Load Serving Entities, the Market Monitoring Unit, and FERC \nsubject to appropriate data protection safeguards required by Operating Agreement, section \n18.17. \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 entity bound by the Operating Agreement serving or contracted to \nserve a Large Load that is or will be in service prior to June 1, 2027, shall provide the \ninformation required by RAA, Schedule 11.B.1 to the Office of the Interconnection by \nMarch 1, 2027.  \nPage 59"},{"page":125,"startToken":41410,"endToken":41534,"text":"(b) \nEach entity bound by the Operating Agreement serving or contracted to \nserve a Large Load that will be in service on or after June 1, 2027, shall provide the \ninformation required by RAA, Schedule 11.B.1 to the Office of the Interconnection before \nthe in-service date of the Large Load. \n \nEach entity bound by the Operating Agreement shall promptly inform the Office of the \nInterconnection of any change in the information required by RAA, Schedule 11.B.1 with \nrespect to a Large Load served by such entity bound by the Operating Agreement, including \nwhether the entity bound by the Operating Agreement no longer serves the Large Load or \nhas acquired the contractual right to serve a registered Large Load. \nPage 60"}],"sections":[{"p":1,"at":0,"title":"Opening text","method":"opening text","endPage":2,"endAt":1223,"startToken":0,"endToken":416},{"p":2,"at":1223,"title":"I. 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