ER26-3380-000 · 2026-07-31 · PJM Interconnection, L.L.C.

Attachment A - Marked Tariff Records.pdf

Attachment A 
Revisions to the 
PJM Open Access Transmission Tariff 
and PJM Reliability Assurance 
Agreement 
(Marked/Redline Format)

Definitions – C - D 
 
Canadian Guaranty: 
 
“Canadian Guaranty” shall mean a Corporate Guaranty provided by an Affiliate of a Participant 
that is domiciled in Canada, and meets all of the provisions of Tariff, Attachment Q. 
 
Cancellation Costs: 
 
“Cancellation Costs” shall mean costs and liabilities incurred in connection with: (a) cancellation 
of supplier and contractor written orders and agreements entered into to design, construct and 
install Attachment Facilities, Direct Assignment Facilities and/or Customer-Funded Upgrades, 
and/or (b) completion of some or all of the required Attachment Facilities, Direct Assignment 
Facilities and/or Customer-Funded Upgrades, or specific unfinished portions and/or removal of 
any or all of such facilities which have been installed, to the extent required for the Transmission 
Provider and/or Transmission Owner(s) to perform their respective obligations under Tariff, Part 
IV and/or Part VI. 
 
Capacity: 
 
“Capacity” shall mean the installed capacity requirement of the Reliability Assurance Agreement 
or similar such requirements as may be established. 
 
Capacity Emergency Transfer Limit: 
 
“Capacity Emergency Transfer Limit” or “CETL” shall have the meaning provided in the 
Reliability Assurance Agreement. 
 
Capacity Emergency Transfer Objective: 
 
“Capacity Emergency Transfer Objective” or “CETO” shall have the meaning provided in the 
Reliability Assurance Agreement. 
 
Capacity Export Transmission Customer: 
 
“Capacity Export Transmission Customer” shall mean a customer taking point to point 
transmission service under Tariff, Part II to export capacity from a generation resource located in 
the PJM Region that has qualified for an exception to the RPM must-offer requirement as 
described in Tariff, Attachment DD, section 6.6(g). 
 
Capacity Import Limit: 
 
“Capacity Import Limit” shall have the meaning provided in the Reliability Assurance 
Agreement. 
 
Capacity Interconnection Rights:

“Capacity Interconnection Rights” shall mean the rights to input generation as a Generation 
Capacity Resource into the Transmission System at the Point of Interconnection where the 
generating facilities connect to the Transmission System. 
 
Capacity Market Buyer: 
 
“Capacity Market Buyer” shall mean a Member that submits bids to buy Capacity Resources in 
any Incremental Auction.   
 
Capacity Market Seller: 
 
“Capacity Market Seller” shall mean a Member that owns, or has the contractual authority to 
control the output or load reduction capability of, a Capacity Resource, that has not transferred 
such authority to another entity, and that offers such resource in the Base Residual Auction or an 
Incremental Auction. 
 
Capacity Performance Transition Incremental Auction: 
 
“Capacity Performance Transition Incremental Auction” shall have the meaning specified in 
Tariff, Attachment DD, section 5.14D. 
 
Capacity Resource: 
 
“Capacity Resource” shall have the meaning provided in the Reliability Assurance Agreement. 
 
Capacity Resource with State Subsidy:  
 
“Capacity Resource with State Subsidy” shall mean (1) a Capacity Resource that is offered into 
an RPM Auction or otherwise assumes an RPM commitment for which the Capacity Market 
Seller receives or is entitled to receive one or more State Subsidies for the applicable Delivery 
Year; (2) a Capacity Resource that has not cleared an RPM Auction for the Delivery Year for 
which the Capacity Market Seller last received a State Subsidy (or any subsequent Delivery 
Year) shall still be considered a Capacity Resource with State Subsidy upon the expiration of 
such State Subsidy until the resource clears an RPM Auction; (3) a Capacity Resource that is the 
subject of a bilateral transaction (including but not limited to those reported pursuant to Tariff, 
Attachment DD, section 4.6) shall be deemed a Capacity Resource with State Subsidy to the 
extent an owner of the facility supporting the Capacity Resource is entitled to a State Subsidy 
associated with such facility even if the Capacity Market Seller is not entitled to a State Subsidy; 
and (4) any Jointly Owned Cross-Subsidized Capacity Resource.  
 
Capacity Resource Clearing Price: 
 
“Capacity Resource Clearing Price” shall mean the price calculated for a Capacity Resource that 
offered and cleared in a Base Residual Auction or Incremental Auction, in accordance with 
Tariff, Attachment DD, section 5.

Capacity Storage Resource: 
 
“Capacity Storage Resource” shall mean any Energy Storage Resource that participates in the 
Reliability Pricing Model or is otherwise treated as capacity in PJM’s markets such as through a 
Fixed Resource Requirement Capacity Plan. 
 
Capacity Transfer Right: 
 
“Capacity Transfer Right” shall mean a right, allocated to LSEs serving load in a Locational 
Deliverability Area, to receive payments, based on the transmission import capability into such 
Locational Deliverability Area, that offset, in whole or in part, the charges attributable to the 
Locational Price Adder, if any, included in the Zonal Capacity Price calculated for a Locational 
Delivery Area. 
 
Capacity Transmission Injection Rights: 
 
“Capacity Transmission Injection Rights” shall mean the rights to schedule energy and capacity 
deliveries at a Point of Interconnection of a Merchant Transmission Facility with the 
Transmission System. Capacity Transmission Injection Rights may be awarded only to a 
Merchant D.C. Transmission Facility and/or Controllable A.C. Merchant Transmission Facilities 
that connects the Transmission System to another control area. Deliveries scheduled using 
Capacity Transmission Injection Rights have rights similar to those under Firm Point-to-Point 
Transmission Service or, if coupled with a generating unit external to the PJM Region that 
satisfies all applicable criteria specified in the PJM Manuals, similar to Capacity Interconnection 
Rights. 
 
Charge Economic Maximum Megawatts: 
 
“Charge Economic Maximum Megawatts” shall mean the greatest magnitude of megawatt power 
consumption available for charging in economic dispatch by an Energy Storage Resource Model 
Participant or Open-Loop Hybrid Resource in Continuous Mode or in Charge Mode.  Charge 
Economic Maximum Megawatts shall be the Economic Minimum for an Energy Storage 
Resource or Open-Loop Hybrid Resource in Charge Mode or in Continuous Mode. 
 
Charge Economic Minimum Megawatts: 
 
“Charge Economic Minimum Megawatts” shall mean the smallest magnitude of megawatt power 
consumption available for charging in economic dispatch by an Energy Storage Resource Model 
Participant or Open-Loop Hybrid Resource in Charge Mode.  Charge Economic Minimum 
Megawatts shall be the Economic Maximum for an Energy Storage Resource or Open-Loop 
Hybrid Resource in Charge Mode. 
 
Charge Mode:

“Charge Mode” shall mean the mode of operation of an Energy Storage Resource Model 
Participant or Open-Loop Hybrid Resource that only includes negative megawatt quantities (i.e., 
the Energy Storage Resource Model Participant or Open-Loop Hybrid Resource is only 
withdrawing megawatts from the grid).   
 
Charge Ramp Rate: 
 
“Charge Ramp Rate” shall mean the Ramping Capability of an Energy Storage Resource Model 
Participant or Open-Loop Hybrid Resource in Charge Mode. 
 
Cleared Capacity Resource with State Subsidy: 
 
“Cleared Capacity Resource with State Subsidy” shall mean a Capacity Resource with State 
Subsidy that has cleared in an RPM Auction for a Delivery Year that is prior to the 2022/2023 
Delivery Year or, starting with 2022/2023 Delivery Year, the MWs (in installed capacity) 
comprising a Capacity Resource with State Subsidy that have cleared an RPM Auction pursuant 
to its Sell Offer at or above its resource-specific MOPR Floor Offer Price or the applicable 
default New Entry MOPR Floor Offer Price and since then, any of those MWs (in installed 
capacity) comprising a Capacity Resource with State Subsidy have been, the subject of a Sell 
Offer into the Base Residual Auction or included in an FRR Capacity Plan at the time of the 
Base Residual Auction for the relevant Delivery Year.   
 
Closed-Loop Hybrid Resource: 
 
“Closed-Loop Hybrid Resource” shall mean a Hybrid Resource without a storage component, or 
that does not operate by charging its storage component from the grid. 
 
Cold/Warm/Hot Notification Time: 
 
“Cold/Warm/Hot Notification Time” shall mean the time interval between PJM notification and 
the beginning of the start sequence for a generating unit that is currently in its cold/warm/hot 
temperature state. The start sequence may include steps such as any valve operation, starting feed 
water pumps, startup of auxiliary equipment, etc. 
 
Cold/Warm/Hot Start-up Time: 
 
For all generating units that are not combined cycle units, “Cold/Warm/Hot Start-up Time” shall 
mean the time interval, measured in hours, from the beginning of the start sequence to the point 
after generator breaker closure, which is typically indicated by telemetered or aggregated State 
Estimator megawatts greater than zero for a generating unit in its cold/warm/hot temperature 
state. For combined cycle units, “Cold/Warm/Hot Start-up Time” shall mean the time interval 
from the beginning of the start sequence to the point after first combustion turbine generator 
breaker closure in its cold/warm/hot temperature state, which is typically indicated by 
telemetered or aggregated State Estimator megawatts greater than zero. For all generating units, 
the start sequence may include steps such as any valve operation, starting feed water pumps, 
startup of auxiliary equipment, etc. Other more detailed actions that could signal the beginning of

the start sequence could include, but are not limited to, the operation of pumps, condensers, fans, 
water chemistry evaluations, checklists, valves, fuel systems, combustion turbines, starting 
engines or systems, maintaining stable fuel/air ratios, and other auxiliary equipment necessary 
for startup. 
 
Cold Weather Alert: 
 
“Cold Weather Alert” shall mean the notice that PJM provides to PJM Members, Transmission 
Owners, resource owners and operators, customers, and regulators to prepare personnel and 
facilities for expected extreme cold weather conditions. 
 
Collateral: 
 
“Collateral” shall be a cash deposit, including any interest thereon, or a Letter of Credit issued 
for the benefit of PJM or PJMSettlement, in an amount and form determined by and acceptable 
to PJM or PJMSettlement, provided by a Participant to PJM or PJMSettlement as credit support 
in order to participate in the PJM Markets or take Transmission Service.  “Collateral” shall also 
include surety bonds, except for the purpose of satisfying the FTR Credit Requirement, in which 
case only a cash deposit or Letter of Credit will be acceptable. 
 
Collateral Call: 
 
“Collateral Call” shall mean a notice to a Participant that additional Collateral, or possibly early 
payment, is required in order to remain in, or to regain, compliance with Tariff, Attachment Q. 
 
Co-Located Resource: 
 
“Co-Located Resource” shall mean a component of a Mixed Technology Facility that operates in 
the capacity, energy, and/or ancillary services market(s) as a separate resource from the other 
components of such facility. 
 
Commencement Date: 
 
“Commencement Date” shall mean the date on which Interconnection Service commences in 
accordance with an Interconnection Service Agreement. 
 
Committed Offer: 
 
The “Committed Offer” shall mean 1) for pool-scheduled resources, an offer on which a resource 
was scheduled by the Office of the Interconnection for a particular clock hour for an Operating 
Day, and 2) for self-scheduled resources, either the offer on which the Market Seller has elected 
to schedule the resource or the applicable offer for the resource determined pursuant to Operating 
Agreement, Schedule 1, section 6.4, and the parallel provisions of Tariff, Attachment K-
Appendix, section 6.4, or Operating Agreement, Schedule 1, section 6.6, and the parallel 
provisions of Tariff, Attachment K-Appendix, section 6.6, for a particular clock hour for an 
Operating Day.

Completed Application: 
 
“Completed Application” shall mean an application that satisfies all of the information and other 
requirements of the Tariff, including any required deposit. 
 
Compliance Aggregation Area (CAA): 
 
“Compliance Aggregation Area” or “CAA” shall mean a geographic area of Zones or sub-Zones 
that are electrically-contiguous and experience for the relevant Delivery Year, based on Resource 
Clearing Prices of, for Delivery Years through May 31, 2018, Annual Resources and for the 
2018/2019 Delivery Year and subsequent Delivery Years, Capacity Performance Resources, the 
same locational price separation in the Base Residual Auction, the same locational price 
separation in the First Incremental Auction, the same locational price separation in the Second 
Incremental Auction, the same locational price separation in the Third Incremental Auction. 
 
Component DER: 
 
“Component DER” shall mean any resource, within the PJM Region, that is located on a 
distribution system, any subsystem thereof, or behind a customer meter, and is used in a DER 
Aggregation Resource by a DER Aggregator to participate in the energy, capacity, and/or 
ancillary services markets of PJM through the DER Aggregator Participation Model.  A 
Component DER may not exceed 5 MW.   
 
Composite Energy Offer:  
 
“Composite Energy Offer” for generation resources shall mean the sum (in $/MWh) of the 
Incremental Energy Offer and amortized Start-Up Costs and amortized No-load Costs, and for 
Economic Load Response Participant resources the sum (in $/MWh) of the Incremental Energy 
Offer and amortized shutdown costs, as determined in accordance with Tariff, Attachment K-
Appendix, section 2.4 and Tariff, Attachment K-Appendix, section 2.4A and the PJM Manuals. 
 
Conditional Incremental Auction: 
 
“Conditional Incremental Auction” shall mean an Incremental Auction conducted for a Delivery 
Year if and when necessary to secure commitments of additional capacity to address reliability 
criteria violations arising from the delay in a Backbone Transmission upgrade that was modeled 
in the Base Residual Auction for such Delivery Year. 
 
Conditioned State Support: 
 
“Conditioned State Support” shall mean any financial benefit required or incentivized by a state, 
or political subdivision of a state acting in its sovereign capacity, that is provided outside of PJM 
Markets and in exchange for the sale of a FERC-jurisdictional product conditioned on clearing in 
any RPM Auction, where “conditioned on clearing in any RPM Auction” refers to specific 
directives as to the level of the offer that must be entered for the relevant Generation Capacity

Resource in the RPM Auction or directives that the Generation Capacity Resource is required to 
clear in any RPM Auction.  Conditioned State Support shall not include any Legacy Policy.   
 
CONE Area: 
 
“CONE Area” shall mean the areas listed in Tariff, Attachment DD, section 5.10(a)(iv)(A) and 
any LDAs established as CONE Areas pursuant to Tariff, Attachment DD, section 
5.10(a)(iv)(B).  
 
Confidential Information: 
 
“Confidential Information” shall mean any confidential, proprietary, or trade secret information 
of a plan, specification, pattern, procedure, design, device, list, concept, policy, or compilation 
relating to the present or planned business of a New Service Customer, Transmission Owner, or 
other Interconnection Party or Construction Party, which is designated as confidential by the 
party supplying the information, whether conveyed verbally, electronically, in writing, through 
inspection, or otherwise, and shall include, without limitation, all information relating to the 
producing party’s technology, research and development, business affairs and pricing, and any 
information supplied by any New Service Customer, Transmission Owner, or other 
Interconnection Party or Construction Party to another such party prior to the execution of an 
Interconnection Service Agreement or a Construction Service Agreement. 
 
Congestion Price: 
 
“Congestion Price” shall mean the congestion component of the Locational Marginal Price, 
which is the effect on transmission congestion costs (whether positive or negative) associated 
with increasing the output of a generation resource or decreasing the consumption by a Demand 
Resource, based on the effect of increased generation from or consumption by the resource on 
transmission line loadings, calculated as specified in Operating Agreement, Schedule 1, section 
2, and the parallel provisions of Tariff, Attachment K-Appendix. 
 
Consolidated Transmission Owners Agreement, PJM Transmission Owners Agreement or 
Transmission Owners Agreement: 
 
“Consolidated Transmission Owners Agreement,” “PJM Transmission Owners Agreement” or 
“Transmission Owners Agreement” shall mean the certain Consolidated Transmission Owners 
Agreement dated as of December 15, 2005, by and among the Transmission Owners and by and 
between the Transmission Owners and PJM Interconnection, L.L.C. on file with the 
Commission, as amended from time to time. 
 
Constraint Relaxation Logic:  
 
“Constraint Relaxation Logic” shall mean the logic applied in the market clearing software 
where the transmission limit is increased to prevent the Transmission Constraint Penalty Factor 
from setting the Marginal Value of a transmission constraint.

Constructing Entity: 
 
“Constructing Entity” shall mean either the Transmission Owner or the New Services Customer, 
depending on which entity has the construction responsibility pursuant to Tariff, Part VI and the 
applicable Construction Service Agreement; this term shall also be used to refer to an 
Interconnection Customer with respect to the construction of the Customer Interconnection 
Facilities. 
 
Construction Party: 
 
“Construction Party” shall mean a party to a Construction Service Agreement.  “Construction 
Parties” shall mean all of the Parties to a Construction Service Agreement. 
 
Construction Service Agreement: 
 
“Construction Service Agreement” shall mean either an Interconnection Construction Service 
Agreement or an Upgrade Construction Service Agreement. 
 
Contingent Facilities: 
 
“Contingent Facilities” shall mean those unbuilt Interconnection Facilities and Network 
Upgrades upon which the Interconnection Request’s costs, timing, and study findings are 
dependent and, if delayed or not built, could cause a need for restudies of the Interconnection 
Request or a reassessment of the Interconnection Facilities and/or Network Upgrades and/or 
costs and timing. 
 
Continuous Mode: 
 
“Continuous Mode” shall mean the mode of operation of an Energy Storage Resource Model 
Participant or Open-Loop Hybrid Resource that includes both negative and positive megawatt 
quantities (i.e., the Energy Storage Resource Model Participant or Open-Loop Hybrid Resource 
is capable of continually and immediately transitioning from withdrawing megawatt quantities 
from the grid to injecting megawatt quantities onto the grid or injecting megawatts to 
withdrawing megawatts).  Energy Storage Resource Model Participants or Open-Loop Hybrid 
Resource operating in Continuous Mode are considered to have an unlimited ramp rate.  
Continuous Mode requires Discharge Economic Maximum Megawatts to be zero or correspond 
to an injection, and Charge Economic Maximum Megawatts to be zero or correspond to a 
withdrawal. 
 
Control Area: 
 
“Control Area” shall mean an electric power system or combination of electric power systems 
bounded by interconnection metering and telemetry to which a common automatic generation 
control scheme is applied in order to:

(1) 
match the power output of the generators within the electric power system(s) and 
energy purchased from entities outside the electric power system(s), with the load within the 
electric power system(s); 
 
 
(2) 
maintain scheduled interchange with other Control Areas, within the limits of 
Good Utility Practice; 
 
 
(3) 
maintain the frequency of the electric power system(s) within reasonable limits in 
accordance with Good Utility Practice; and 
 
 
(4) 
provide sufficient generating capacity to maintain operating reserves in 
accordance with Good Utility Practice. 
 
Control Zone: 
 
“Control Zone” shall have the meaning given in the Operating Agreement. 
 
Controllable A.C. Merchant Transmission Facilities: 
 
“Controllable A.C. Merchant Transmission Facilities” shall mean transmission facilities that (1) 
employ technology which Transmission Provider reviews and verifies will permit control of 
the amount and/or direction of power flow on such facilities to such extent as to effectively 
enable the controllable facilities to be operated as if they were direct current transmission 
facilities, and (2) that are interconnected with the Transmission System pursuant to Tariff, Part 
IV and Part VI. 
 
Coordinated External Transaction: 
 
“Coordinated External Transaction” shall mean a transaction to simultaneously purchase and sell 
energy on either side of a CTS Enabled Interface in accordance with the procedures of Operating 
Agreement, Schedule 1, section 1.13, and the parallel provisions of Tariff, Attachment K-
Appendix. 
 
Coordinated Transaction Scheduling: 
 
“Coordinated Transaction Scheduling” or “CTS” shall mean the scheduling of Coordinated 
External Transactions at a CTS Enabled Interface in accordance with the procedures of 
Operating Agreement, Schedule 1, section 1.13, and the parallel provisions of Tariff, Attachment 
K-Appendix. 
 
Corporate Guaranty: 
 
“Corporate Guaranty” shall mean a legal document, in a form acceptable to PJM and/or 
PJMSettlement, used by a Credit Affiliate of an entity to guaranty the obligations of another 
entity.

Cost of New Entry: 
 
“Cost of New Entry” or “CONE” shall mean the nominal levelized cost of a Reference Resource, 
as determined in accordance with Tariff, Attachment DD, section 5. 
 
Costs: 
 
As used in Tariff, Part IV, Part VI and related attachments, “Costs” shall mean costs and 
expenses, as estimated or calculated, as applicable, including, but not limited to, capital 
expenditures, if applicable, and overhead, return, and the costs of financing and taxes and any 
Incidental Expenses. 
 
Counterparty:  
 
“Counterparty” shall mean PJMSettlement as the contracting party, in its name and own right 
and not as an agent, to an agreement or transaction with a Market Participant or other entities, 
including the agreements and transactions with customers regarding transmission service and 
other transactions under the PJM Tariff and the Operating Agreement.  PJMSettlement shall not 
be a counterparty to (i) any bilateral transactions between Members, or (ii) any Member’s self-
supply of energy to serve its load, or (iii) any Member’s self-schedule of energy reported to the 
Office of the Interconnection to the extent that energy serves that Member’s own load. 
 
Credit Affiliate: 
 
“Credit Affiliate” shall mean Principals, corporations, partnerships, firms, joint ventures, 
associations, joint stock companies, trusts, unincorporated organizations or entities, one of which 
directly or indirectly controls the other or that are both under common Control. “Control,” as that 
term is used in this definition, shall mean the possession, directly or indirectly, of the power to 
direct the management or policies of a person or an entity. 
 
Credit Available for Export Transactions: 
 
“Credit Available for Export Transactions” shall mean a designation of credit to be used for 
Export Transactions that is allocated by each Market Participant from its Credit Available for 
Virtual Transactions, and which reduces the Market Participant's Credit Available for Virtual 
Transactions accordingly. 
 
Credit Available for Virtual Transactions: 
 
“Credit Available for Virtual Transactions” shall mean the Market Participant’s Working Credit 
Limit for Virtual Transactions calculated on its credit provided in compliance with its Peak 
Market Activity requirement plus available credit submitted above that amount, less any unpaid 
billed and unbilled amounts owed to PJMSettlement, plus any unpaid unbilled amounts owed by 
PJMSettlement to the Market Participant, less any applicable credit required for Minimum 
Participation Requirements, FTRs, RPM activity,  or other credit requirement determinants as 
defined in Tariff, Attachment Q.

Credit Breach: 
 
“Credit Breach” shall mean (a) the failure of a Participant to perform, observe, meet or comply 
with any requirements of Tariff, Attachment Q or other provisions of the Agreements, other than 
a Financial Default, or (b) a determination by PJM and notice to the Participant that a Participant 
represents an unreasonable credit risk to the PJM Markets; that, in either event, has not been 
cured or remedied after any required notice has been given and any cure period has elapsed. 
 
Credit-Limited Offer: 
 
“Credit-Limited Offer” shall mean a Sell Offer that is submitted by a Market Participant in an 
RPM Auction subject to a maximum credit requirement specified by such Market Participant. 
 
Credit Support Default: 
 
“Credit Support Default,” shall mean (a) the failure of any Guarantor of a Market Participant to 
make any payment, or to perform, observe, meet or comply with any provisions of the applicable 
Guaranty or Credit Support Document that has not been cured or remedied, after any required 
notice has been given and an opportunity to cure (if any) has elapsed, (b) a representation made 
or deemed made by a Guarantor in any Credit Support Document that proves to be false, 
incorrect or misleading in any material respect when made or deemed made, (c) the failure of a 
Guaranty or other Credit Support Document to be in full force and effect prior to the satisfaction 
of all obligations of such Participant to PJM, without PJM’s consent, or (d) a Guarantor 
repudiating, disaffirming, disclaiming or rejecting, in whole or in part, its obligations under the 
Guaranty or challenging the validity of the Guaranty.  
 
Credit Support Document:  
 
“Credit Support Document” shall mean any agreement or instrument in any way guaranteeing or 
securing any or all of a Participant’s obligations under the Agreements (including, without 
limitation, the provisions of Tariff, Attachment Q), any agreement entered into under, pursuant 
to, or in connection with the Agreements or any agreement entered into under, pursuant to, or in 
connection with the Agreements and/or any other agreement to which PJM, PJMSettlement and 
the Participant are parties, including, without limitation, any Corporate Guaranty, Letter of 
Credit, or agreement granting PJM and PJMSettlement a security interest. 
 
Critical Natural Gas Infrastructure:  
 
“Critical Natural Gas Infrastructure” shall mean locations with electrical loads that are involved 
in natural gas production, processing, intrastate and interstate transmission and distribution 
pipeline facility as defined by NERC/FERC standard(s); and until such NERC/FERC standard(s) 
is developed, is defined as electric loads that are involved in natural gas production, processing, 
intrastate and interstate transmission and distribution pipeline facility, which if curtailed, will 
impact the delivery of natural gas to bulk-power system natural gas-fired generation.

Cross-Border: 
 
When used to describe Network Integration Transmission Service, Network External Designated 
Transmission Service or Point-to-Point Transmission Service, “Cross-Border” shall mean 
transmission service where the capacity and/or energy is delivered from a resource that is not 
part of the PJM Transmission System and/or to load that is not part of the PJM Transmission 
System. 
 
CTS Enabled Interface: 
 
“CTS Enabled Interface” shall mean an interface between the PJM Control Area and an adjacent 
Control Area at which the Office of the Interconnection has authorized the use of Coordinated 
Transaction Scheduling (“CTS”). The CTS Enabled Interfaces between the PJM Control Area 
and the New York Independent System Operator, Inc. Control Area shall be designated in 
Schedule A to the Joint Operating Agreement Among and Between New York Independent 
System Operator Inc. and PJM Interconnection, L.L.C. (PJM Rate Schedule FERC No. 45).  The 
CTS Enabled Interfaces between the PJM Control Area and the Midcontinent Independent 
System Operator, Inc. shall be designated consistent with Attachment 3, section 2 of the Joint 
Operating Agreement between Midcontinent Independent System Operator, Inc. and PJM 
Interconnection, L.L.C. 
 
CTS Interface Bid: 
 
“CTS Interface Bid” shall mean a unified real-time bid to simultaneously purchase and sell 
energy on either side of a CTS Enabled Interface in accordance with the procedures of Operating 
Agreement, Schedule 1, section 1.13, and the parallel provisions of Tariff, Attachment K-
Appendix. 
 
Curtailment: 
 
“Curtailment” shall mean a reduction in firm or non-firm transmission service in response to a 
transfer capability shortage as a result of system reliability conditions. 
 
Curtailment Service Provider: 
 
“Curtailment Service Provider” or “CSP” shall mean a Member or a Special Member, which 
action on behalf of itself or one or more other Members or non-Members, participates in the PJM 
Interchange Energy Market, Ancillary Services markets, and/or Reliability Pricing Model by 
causing a reduction in demand. 
 
Customer Facility: 
 
“Customer Facility” shall mean Generation Facilities or Merchant Transmission Facilities 
interconnected with or added to the Transmission System pursuant to an Interconnection Request 
under Subparts A of Tariff, Part IV.

Customer-Funded Upgrade: 
 
“Customer-Funded Upgrade” shall mean any Network Upgrade, Local Upgrade, or Merchant 
Network Upgrade for which cost responsibility (i) is imposed on an Interconnection Customer or 
an Eligible Customer pursuant to Tariff, Part VI, section 217, or (ii) is voluntarily undertaken by 
a New Service Customer in fulfillment of an Upgrade Request.  No Network Upgrade, Local 
Upgrade or Merchant Network Upgrade or other transmission expansion or enhancement shall be 
a Customer-Funded Upgrade if and to the extent that the costs thereof are included in the rate 
base of a public utility on which a regulated return is earned. 
 
Customer Interconnection Facilities: 
 
“Customer Interconnection Facilities” shall mean all facilities and equipment owned and/or 
controlled, operated and maintained by Interconnection Customer on Interconnection Customer’s 
side of the Point of Interconnection identified in the appropriate appendices to the 
Interconnection Service Agreement and to the Interconnection Construction Service Agreement, 
including any modifications, additions, or upgrades made to such facilities and equipment, that 
are necessary to physically and electrically interconnect the Customer Facility with the 
Transmission System. 
 
Daily Deficiency Rate: 
 
“Daily Deficiency Rate” shall mean the rate employed to assess certain deficiency charges as 
detailed under Tariff, Attachment DD, section 7. 
 
Daily Unforced Capacity Obligation: 
 
“Daily Unforced Capacity Obligation” shall mean the capacity obligation of a Load Serving 
Entity during the Delivery Year, determined in accordance with  Reliability Assurance 
Agreement, Schedule 8, or, as to an FRR entity, in Reliability Assurance Agreement, Schedule 
8.1. 
 
Day-ahead Congestion Price: 
 
“Day-ahead Congestion Price” shall mean the Congestion Price resulting from the Day-ahead 
Energy Market. 
 
Day-ahead Energy Market: 
 
“Day-ahead Energy Market” shall mean the schedule of commitments for the purchase or sale of 
energy and payment of Transmission Congestion Charges developed by the Office of the 
Interconnection as a result of the offers and specifications submitted in accordance with 
Operating Agreement, Schedule 1, section 1.10 and the parallel provisions of Tariff, Attachment 
K-Appendix. 
 
Day-ahead Energy Market Injection Congestion Credits:

“Day-ahead Energy Market Injection Congestion Credits” shall mean those congestion credits 
paid to Market Participants for supply transactions in the Day-ahead Energy Market including 
generation schedules, Increment Offers, Up-to Congestion Transactions, import transactions, and 
Day-Ahead Pseudo-Tie Transactions. 
 
Day-ahead Energy Market Transmission Congestion Charges: 
 
“Day-ahead Energy Market Transmission Congestion Charges” shall be equal to the sum of Day-
ahead Energy Market Withdrawal Congestion Charges minus [the sum of Day-ahead Energy 
Market Injection Congestion Credits plus any congestion charges calculated pursuant to the Joint 
Operating Agreement between the Midcontinent Independent Transmission System Operator, 
Inc. and PJM Interconnection, L.L.C. (PJM Rate Schedule FERC No. 38), plus any congestion 
charges calculated pursuant to the Joint Operating Agreement Among and Between New York 
Independent System Operator Inc. and PJM Interconnection, L.L.C. (PJM Rate Schedule FERC 
No. 45), plus any congestion charges calculated pursuant to agreements between the Office of 
the Interconnection and other entities, as applicable)]. 
 
Day-ahead Energy Market Withdrawal Congestion Charges: 
 
“Day-ahead Energy Market Withdrawal Congestion Charges” shall mean those congestion 
charges collected from Market Participants for withdrawal transactions in the Day-ahead Energy 
Market from transactions including Demand Bids, Decrement Bids, Up-to Congestion 
Transactions, Export Transactions, and Day-Ahead Pseudo-Tie Transactions. 
 
Day-ahead Loss Price: 
 
“Day-ahead Loss Price” shall mean the Loss Price resulting from the Day-ahead Energy Market. 
 
Day-ahead Prices: 
 
“Day-ahead Prices” shall mean the Locational Marginal Prices resulting from the Day-ahead 
Energy Market. 
 
Day-Ahead Pseudo-Tie Transaction:  
 
“Day-Ahead Pseudo-Tie Transaction” shall mean a transaction scheduled in the Day-ahead 
Energy Market to the PJM-MISO interface from a generator within the PJM balancing authority 
area that Pseudo-Ties into the MISO balancing authority area. 
 
Day-ahead Settlement Interval:  
 
“Day-ahead Settlement Interval” shall mean the interval used by settlements, which shall be 
every one clock hour.  
 
Day-ahead State of Charge:

“Day-ahead State of Charge” shall mean the prospective State of Charge of an Energy Storage 
Resource Model Participant as offered into the Day-ahead Energy Market according to the 
procedures described in the PJM Manuals, measured in units of megawatt-hours. Day-ahead 
State of Charge for an interval represents the State of Charge at the beginning of that interval. 
 
Day-ahead System Energy Price: 
 
“Day-ahead System Energy Price” shall mean the System Energy Price resulting from the Day-
ahead Energy Market. 
 
Deactivation: 
 
“Deactivation” shall mean the retirement or mothballing of a generating unit governed by Tariff, 
Part V. 
 
Deactivation Avoidable Cost Credit: 
 
“Deactivation Avoidable Cost Credit” shall mean the credit paid to Generation Owners pursuant 
to Tariff, Part V, section 114. 
 
Deactivation Avoidable Cost Rate: 
 
“Deactivation Avoidable Cost Rate” shall mean the formula rate established pursuant to Tariff, 
Part V, section 115 of this Tariff. 
 
Deactivation Date: 
 
“Deactivation Date” shall mean the date a generating unit within the PJM Region is either retired 
or mothballed and ceases to operate. 
 
Decrement Bid: 
 
“Decrement Bid” shall mean a type of Virtual Transaction that is a bid to purchase energy at a 
specified location in the Day-ahead Energy Market.  A cleared Decrement Bid results in 
scheduled load at the specified location in the Day-ahead Energy Market. 
 
Default: 
 
As used in the Interconnection Service Agreement and Construction Service Agreement, 
“Default” shall mean the failure of a Breaching Party to cure its Breach in accordance with the 
applicable provisions of an Interconnection Service Agreement or Construction Service 
Agreement. 
 
Delivering Party:

“Delivering Party” shall mean the entity supplying capacity and energy to be transmitted at 
Point(s) of Receipt. 
 
Delivery Year: 
 
“Delivery Year” shall mean the Planning Period for which a Capacity Resource is committed 
pursuant to the auction procedures specified in Tariff, Attachment DD, or pursuant to an FRR 
Capacity Plan under Reliability Assurance Agreement, Schedule 8.1. 
 
Demand Bid: 
 
“Demand Bid” shall mean a bid, submitted by a Load Serving Entity in the Day-ahead Energy 
Market, to purchase energy at its contracted load location, for a specified timeframe and 
megawatt quantity, that if cleared will result in energy being scheduled at the specified location 
in the Day-ahead Energy Market and in the physical transfer of energy during the relevant 
Operating Day.   
 
Demand Bid Limit: 
 
“Demand Bid Limit” shall mean the largest MW volume of Demand Bids that may be submitted 
by a Load Serving Entity for any hour of an Operating Day, as determined pursuant to Operating 
Agreement, Schedule 1, section 1.10.1B, and the parallel provisions of Tariff, Attachment K-
Appendix. 
 
Demand Bid Screening: 
 
“Demand Bid Screening” shall mean the process by which Demand Bids are reviewed against 
the applicable Demand Bid Limit, and rejected if they would exceed that limit, as determined 
pursuant to Operating Agreement, Schedule 1, section 1.10.1B, and the parallel provisions of 
Tariff, Attachment K-Appendix. 
 
DER Aggregation Resource: 
 
“DER Aggregation Resource” shall be comprised of one or more Component DER.  A DER 
Aggregation Resource is used by a DER Aggregator to participate: (1) in the energy, capacity, 
and/or ancillary services markets of PJM; or (2) in the Reliability Backstop Procurement as an 
RBP Resource to the extent the DER Aggregation Resource meets the requirements set forth in 
Tariff, Attachment, DD, section 18.5(d), through the DER Aggregator Participation Model.  A 
DER Aggregation Resource is capable of satisfying a minimum energy and/or ancillary services 
market offer of 100 kW.  The market participation eligibility of a DER Aggregation Resource 
shall be determined in accordance with the physical and operational characteristics of the 
underlying Component DER that comprise the DER Aggregation Resource. 
 
DER Aggregator:

“DER Aggregator” shall mean an entity that is a Market Participant that: (i) uses one or more 
DER Aggregation Resources to participate in the energy, capacity, and/or ancillary services 
markets of PJM through the DER Aggregator Participation Model; and (ii) has a fully-executed 
DER Aggregator Participation Service Agreement. 
 
DER Aggregator Participation Model: 
 
“DER Aggregator Participation Model” shall mean the participation model described in Tariff, 
Attachment K-Appendix, section 1.4B. 
 
DER Capacity Aggregation Resource: 
 
“DER Capacity Aggregation Resource” shall mean one or more DER Aggregation Resource that 
participates in the Reliability Pricing Model, capable of satisfying a minimum capacity market 
offer of 100 kW, or is otherwise treated as capacity in PJM’s markets, such as through a Fixed 
Resource Requirement Capacity Plan, for the 2028/2029 Delivery Year and all subsequent 
Delivery Years.   
 
Designated Agent: 
 
“Designated Agent” shall mean any entity that performs actions or functions on behalf of the 
Transmission Provider, a Transmission Owner, an Eligible Customer, or the Transmission 
Customer required under the Tariff. 
 
Designated Entity: 
 
“Designated Entity” shall have the same meaning provided in the Operating Agreement. 
 
Direct Assignment Facilities: 
 
“Direct Assignment Facilities” shall mean facilities or portions of facilities that are constructed 
for the sole use/benefit of a particular Transmission Customer requesting service under the 
Tariff.  Direct Assignment Facilities shall be specified in the Service Agreement that governs 
service to the Transmission Customer and shall be subject to Commission approval. 
 
Direct Charging Energy: 
 
“Direct Charging Energy” shall mean the energy that an Energy Storage Resource or Open-Loop 
Hybrid Resource purchases from the PJM Interchange Energy Market and (i) later resells to the 
PJM Interchange Energy Market; or (ii) is lost to conversion inefficiencies, provided that such 
inefficiencies are an unavoidable component of the conversion, storage, and discharge process 
that is used to resell energy back to the PJM Interchange Energy Market. 
 
Direct Load Control:

“Direct Load Control” shall mean load reduction that is controlled directly by the Curtailment 
Service Provider’s market operations center or its agent, in response to PJM instructions. 
 
Discharge Economic Maximum Megawatts: 
 
“Discharge Economic Maximum Megawatts” shall mean the maximum megawatt power output 
available for discharge in economic dispatch by an Energy Storage Resource Model Participant 
or Open-Loop Hybrid Resource in Continuous Mode or in Discharge Mode. Discharge 
Economic Maximum Megawatts shall be the Economic Maximum for an Energy Storage 
Resource or Open-Loop Hybrid Resource in Discharge Mode or in Continuous Mode. 
 
Discharge Economic Minimum Megawatts: 
 
“Discharge Economic Minimum Megawatts” shall mean the minimum megawatt power output 
available for discharge in economic dispatch by an Energy Storage Resource Model Participant 
or Open-Loop Hybrid Resource in Discharge Mode.  Discharge Economic Minimum Megawatts 
shall be the Economic Minimum for an Energy Storage Resource or Open-Loop Hybrid 
Resource in Discharge Mode. 
 
Discharge Mode: 
 
“Discharge Mode” shall mean the mode of operation of an Energy Storage Resource Model 
Participant or Open-Loop Hybrid Resource that only includes positive megawatt quantities (i.e., 
the Energy Storage Resource Model Participant or Open-Loop Hybrid Resource is only injecting 
megawatts onto the grid).   
 
Discharge Ramp Rate: 
 
“Discharge Ramp Rate” shall mean the Ramping Capability of an Energy Storage Resource 
Model Participant or Open-Loop Hybrid Resource in Discharge Mode. 
 
Dispatch Rate: 
 
“Dispatch Rate” shall mean the control signal, expressed in dollars per megawatt-hour, 
calculated and transmitted continuously and dynamically to direct the output level of all 
generation resources dispatched by the Office of the Interconnection in accordance with the 
Offer Data. 
 
Dispatched Charging Energy:   
 
“Dispatched Charging Energy” shall mean Direct Charging Energy that an Energy Storage 
Resource Model Participant or Open-Loop Hybrid Resource receives from the electric grid 
pursuant to PJM dispatch while providing one of the following services in the PJM markets: 
Energy Imbalance Service pursuant to Tariff, Schedule 4; Regulation; Tier 2 Synchronized 
Reserves; or Reactive Service.  Energy Storage Resource Model Participants and Open-Loop

Hybrid Resource shall be considered to be providing Energy Imbalance Service when they are 
dispatchable by PJM in real-time.   
 
Dynamic Schedule: 
 
“Dynamic Schedule” shall have the same meaning provided in the Operating Agreement. 
 
Dynamic Transfer: 
 
“Dynamic Transfer” shall have the same meaning provided in the Operating Agreement.

Definitions – E - F 
 
Economic-based Enhancement or Expansion: 
 
“Economic-based Enhancement or Expansion” shall have the same meaning provided in the 
Operating Agreement. 
 
Economic Load Response Participant: 
 
“Economic Load Response Participant” shall mean a Member or Special Member that qualifies 
under Operating Agreement, Schedule 1, section 1.5A, and the parallel provisions of Tariff, 
Attachment K-Appendix, section 1.5A, to participate in the PJM Interchange Energy Market 
and/or Ancillary Services markets through reductions in demand. 
 
Economic Load Response Regulation Only Participant:  
 
“Economic Load Response Regulation Only Participant” shall mean a Member or Special 
Member that qualifies under Operating Agreement, Schedule 1, section 1.5A, and the parallel 
provisions of Tariff, Attachment K-Appendix, section 1.5A, and is only eligible to participate in 
the PJM Regulation market. 
 
Economic Maximum: 
 
“Economic Maximum” shall mean the highest incremental MW output level, submitted to PJM 
market systems by a Market Participant, that a unit can achieve while following economic 
dispatch.   
 
Economic Minimum: 
 
“Economic Minimum” shall mean the lowest incremental MW output level, submitted to PJM 
market systems by a Market Participant, that a unit can achieve while following economic 
dispatch. 
 
Effective FTR Holder: 
 
“Effective FTR Holder” shall mean: 
 
(i) For an FTR Holder that is either a (a) privately held company, or (b) a municipality or 
electric cooperative, as defined in the Federal Power Act, such FTR Holder, together with 
any Affiliate, subsidiary or parent of the FTR Holder, any other entity that is under common 
ownership, wholly or partly, directly or indirectly, or has the ability to influence, directly or 
indirectly, the management or policies of the FTR Holder; or  
 
(ii) For an FTR Holder that is a publicly traded company including a wholly owned 
subsidiary of a publicly traded company, such FTR Holder, together with any Affiliate, 
subsidiary or parent of the FTR Holder, any other PJM Member has over 10% common

ownership with the FTR Holder, wholly or partly, directly or indirectly, or has the ability to 
influence, directly or indirectly, the management or policies of the FTR Holder; or  
 
(iii)  an FTR Holder together with any other PJM Member, including also any Affiliate, 
subsidiary or parent of such other PJM Member, with which it shares common ownership, 
wholly or partly, directly or indirectly, in any third entity which is a PJM Member (e.g., a 
joint venture). 
 
 
EFORd: 
 
“EFORd” shall have the meaning specified in the PJM Reliability Assurance Agreement. 
 
Electrical Distance: 
 
“Electrical Distance” shall mean, for a Generation Capacity Resource geographically located 
outside the metered boundaries of the PJM Region, the measure of distance, based on impedance 
and in accordance with the PJM Manuals, from the Generation Capacity Resource to the PJM 
Region. 
 
Eligible Customer: 
 
“Eligible Customer” shall mean: 
 
(i) Any electric utility (including any Transmission Owner and any power marketer), Federal 
power marketing agency, or any person generating electric energy for sale for resale is an 
Eligible Customer under the Tariff.  Electric energy sold or produced by such entity may be 
electric energy produced in the United States, Canada or Mexico.  However, with respect to 
transmission service that the Commission is prohibited from ordering by Section 212(h) of the 
Federal Power Act, such entity is eligible only if the service is provided pursuant to a state 
requirement that the Transmission Provider or Transmission Owner offer the unbundled 
transmission service, or pursuant to a voluntary offer of such service by a Transmission Owner. 
 
(ii) Any retail customer taking unbundled transmission service pursuant to a state requirement 
that the Transmission Provider or a Transmission Owner offer the transmission service, or 
pursuant to a voluntary offer of such service by a Transmission Owner, is an Eligible Customer 
under the Tariff.  As used in Tariff, Part VI, Eligible Customer shall mean only those Eligible 
Customers that have submitted a Completed Application. 
 
Eligible Fast-Start Resource: 
 
“Eligible Fast-Start Resource” shall mean a Fast-Start Resource that is eligible for the 
application of Integer Relaxation during the calculation of Locational Marginal Prices as set 
forth in Tariff, Attachment K-Appendix, section 2.2. 
 
Emergency Action:

“Emergency Action” shall mean (1) any megawatt shortage of the Primary Reserve Requirement 
(as specified in the PJM Manuals) in a Reserve Zone or Reserve Sub-zone, inclusive of any 
adjustments to such requirement to account for system conditions, as determined by the dispatch 
run from the security constrained economic dispatch and where, as specified in the PJM 
Manuals, there is also a Voltage Reduction Warning and reduction of non-critical plant load, 
Manual Load Dump Warning, Maximum Generation Emergency Action, or the curtailment of 
non-essential building loads and Voltage Reduction Warning that encompasses such Reserve 
Zone or Reserve Sub-zone or (2) anytime the Office of Interconnection identifies an emergency 
and issues a load shed directive, Manual Load Dump Action, Voltage Reduction Action, or 
deploy all resources action for an entire Reserve Zone or Reserve Sub-zone. 
 
Emergency Condition: 
 
“Emergency Condition” shall mean a condition or situation (i) that in the judgment of any 
Interconnection Party is imminently likely to endanger life or property; or (ii) that in the 
judgment of the Interconnected Transmission Owner or Transmission Provider is imminently 
likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the 
security of, or damage to, the Transmission System, the Interconnection Facilities, or the 
transmission systems or distribution systems to which the Transmission System is directly or 
indirectly connected; or (iii) that in the judgment of Interconnection Customer is imminently 
likely (as determined in a non-discriminatory manner) to cause damage to the Customer Facility 
or to the Customer Interconnection Facilities.  System restoration and black start shall be 
considered Emergency Conditions, provided that a Generation Interconnection Customer is not 
obligated by an Interconnection Service Agreement to possess black start capability.  Any 
condition or situation that results from lack of sufficient generating capacity to meet load 
requirements or that results solely from economic conditions shall not constitute an Emergency 
Condition, unless one or more of the enumerated conditions or situations identified in this 
definition also exists. 
 
Emergency Load Response Program: 
“Emergency Load Response Program” shall mean the program by which Curtailment Service 
Providers may be compensated by PJM for Demand Resources that will reduce load when 
dispatched by PJM during emergency conditions, and is described in Operating Agreement, 
Schedule 1, section 8  and the parallel provisions of Tariff, Attachment K-Appendix, section 8.  
 
Energy Efficiency Resource: 
 
“Energy Efficiency Resource” shall have the meaning specified in the PJM Reliability Assurance 
Agreement. 
 
Energy Market Opportunity Cost: 
 
“Energy Market Opportunity Cost” shall mean the difference between (a) the forecasted cost to 
operate a specific generating unit when the unit only has an operational limitation due to 
limitations imposed on the unit by Applicable Laws and Regulations, and (b) the forecasted

future Locational Marginal Price at which the generating unit could run while not violating such 
limitations.  Energy Market Opportunity Cost therefore is the value associated with a specific 
generating unit’s lost opportunity to produce energy during a higher valued period of time 
occurring within the same compliance period, which compliance period is determined by the 
applicable regulatory authority and is reflected in the rules set forth in PJM Manual 15.  Energy 
Market Opportunity Costs shall be limited to those resources which are specifically delineated in 
Operating Agreement, Schedule 2. 
 
Energy Resource: 
 
“Energy Resource” shall mean a Generating Facility that is not a Capacity Resource. 
 
Energy Settlement Area: 
 
“Energy Settlement Area” shall mean the bus or distribution of busses that represents the 
physical location of Network Load and by which the obligations of the Network Customer to 
PJM are settled. 
 
Energy Storage Resource: 
 
“Energy Storage Resource” shall mean a resource capable of receiving electric energy from the 
grid and storing it for later injection to the grid that (1) participates in the PJM Energy, Capacity 
and/or Ancillary Services markets as a Market Participant; or (2) may be an RBP Resource to the 
extent that the Energy Storage Resource meets the requirements set forth in Tariff, Attachment 
DD, section 18.5(b).  Open-Loop Hybrid Resources are not 
 Energy Storage Resources. 
 
Energy Storage Resource Model Participant:  
 
“Energy Storage Resource Model Participant” shall mean an Energy Storage Resource utilizing 
the Energy Storage Resource Participation Model.   
 
Energy Storage Resource Participation Model:  
 
“Energy Storage Resource Participation Model” shall mean the participation model accepted by 
the Commission in Docket No. ER19-469-000. 
 
Energy Transmission Injection Rights: 
 
“Energy Transmission Injection Rights” shall mean the rights to schedule energy deliveries at a 
specified point on the Transmission System. Energy Transmission Injection Rights may be 
awarded only to a Merchant D.C. Transmission Facility that connects the Transmission System 
to another control area. Deliveries scheduled using Energy Transmission Injection Rights have 
rights similar to those under Non-Firm Point-to-Point Transmission Service. 
 
Entity Providing Supply Services to Default Retail Service Provider:

“Entity Providing Supply Services to Default Retail Service Provider” shall mean any entity, 
including but not limited to a load aggregator or power marketer, providing supply services to an 
electric distribution company when that electric distribution company is serving as the default 
retail service provider, and that enters into a contract or similar obligation with such electric 
distribution company to serve retail customers who have not selected a competitive retail service 
provider.  
 
Environmental Laws: 
 
“Environmental Laws” shall mean applicable Laws or Regulations relating to pollution or 
protection of the environment, natural resources or human health and safety. 
 
Environmentally-Limited Resource: 
 
“Environmentally-Limited Resource” shall mean a resource which has a limit on its run hours 
imposed by a federal, state, or other governmental agency that will significantly limit its 
availability, on either a temporary or long-term basis. This includes a resource that is limited by a 
governmental authority to operating only during declared PJM capacity emergencies. 
 
Equivalent Load: 
 
“Equivalent Load” shall mean the sum of a Market Participant’s net system requirements to 
serve its customer load in the PJM Region, if any, plus its net bilateral transactions. 
 
Event of Default: 
 
“Event of Default,” as that term is used in Tariff, Attachment Q, shall mean a Financial Default, 
Credit Breach, or Credit Support Default.   
 
Exercise of Buyer-Side Market Power: 
 
“Exercise of Buyer-Side Market Power” shall mean anti-competitive behavior of a Capacity 
Market Seller with a Load Interest, or directed by an entity with a Load Interest, to 
uneconomically lower RPM Auction Sell Offer(s) in order to suppress RPM Auction clearing 
prices for the overall benefit of the Capacity Market Seller’s (and/or affiliates of Capacity 
Market Seller) portfolio of generation and load or that of the directing entity with a Load Interest 
as determined pursuant to Tariff, Attachment DD, section 5.14(h-2)(2)(B). A bilateral contract 
between the Capacity Market Seller and an entity with a Load Interest with the express purpose 
of lowering capacity market clearing prices shall be evidence of the Exercise of Buyer-Side 
Market Power. 
 
Existing Generation Capacity Resource: 
 
“Existing Generation Capacity Resource” shall have the meaning specified in the Reliability 
Assurance Agreement.

Export Credit Exposure: 
  
“Export Credit Exposure” is determined for each Market Participant for a given Operating Day, 
and shall mean the sum of credit exposures for the Market Participant’s Export Transactions for 
that Operating Day and for the preceding Operating Day. 
 
Export Nodal Reference Price: 
 
“Export Nodal Reference Price” at each location is the 97th percentile, shall be, the real-time 
hourly integrated price experienced over the corresponding two-month period in the preceding 
calendar year, calculated separately for peak and off-peak time periods.  The two-month time 
periods used in this calculation shall be January and February, March and April, May and June, 
July and August, September and October, and November and December.  
 
Export Transaction: 
  
“Export Transaction” shall be a transaction by a Market Participant that results in the transfer of 
energy from within the PJM Control Area to outside the PJM Control Area.  Coordinated 
External Transactions that result in the transfer of energy from the PJM Control Area to an 
adjacent Control Area are one form of Export Transaction.   
 
Export Transaction Price Factor: 
 
“Export Transaction Price Factor” for a prospective time interval shall be the greater of (i) PJM’s 
forecast price for the time interval, if available, or (ii) the Export Nodal Reference Price, but 
shall not exceed the Export Transaction’s dispatch ceiling price cap, if any, for that time interval.  
The Export Transaction Price Factor for a past time interval shall be calculated in the same 
manner as for a prospective time interval, except that the Export Transaction Price Factor may 
use a tentative or final settlement price, as available. If an Export Nodal Reference Price is not 
available for a particular time interval, PJM may use an Export Transaction Price Factor for that 
time interval based on an appropriate alternate reference price. 
 
Export Transaction Screening: 
 
“Export Transaction Screening” shall be the process PJM uses to review the Export Credit 
Exposure of Export Transactions against the Credit Available for Export Transactions, and deny 
or curtail all or a portion of an Export Transaction, if the credit required for such transactions is 
greater than the credit available for the transactions.   
 
Export Transactions Net Activity: 
 
“Export Transactions Net Activity” shall mean the aggregate net total, resulting from Export 
Transactions, of (i) Spot Market Energy charges, (ii) Transmission Congestion Charges, and (iii) 
Transmission Loss Charges, calculated as set forth in Operating Agreement, Schedule 1 and the

parallel provisions of Tariff, Attachment K-Appendix.  Export Transactions Net Activity may be 
positive or negative. 
 
Extended Primary Reserve Requirement: 
 
“Extended Primary Reserve Requirement” shall equal the Primary Reserve Requirement in a 
Reserve Zone or Reserve Sub-zone, plus 190 MW, plus any additional reserves scheduled under 
emergency conditions necessary to address operational uncertainty.  The Extended Primary 
Reserve Requirement is calculated in accordance with the PJM Manuals.  
 
Extended Synchronized Reserve Requirement: 
 
“Extended Synchronized Reserve Requirement” shall equal the Synchronized Reserve 
Requirement in a Reserve Zone or Reserve Sub-zone, plus 190 MW, plus any additional reserves 
scheduled under emergency conditions necessary to address operational uncertainty. The 
Extended Synchronized Reserve Requirement is calculated in accordance with the PJM Manuals. 
 
Extended 30-minute Reserve Requirement: 
 
“Extended 30-minute Reserve Requirement” shall equal the 30-minute Reserve Requirement in a 
Reserve Zone or Reserve Sub-zone, plus 190 MW, plus any additional reserves scheduled under 
emergency conditions necessary to address operational uncertainty.  The Extended 30-minute 
Reserve Requirement is calculated in accordance with the PJM Manuals. 
 
External Market Buyer: 
 
“External Market Buyer” shall mean a Market Buyer making purchases of energy from the PJM 
Interchange Energy Market for consumption by end-users outside the PJM Region, or for load in 
the PJM Region that is not served by Network Transmission Service. 
 
External Resource: 
 
“External Resource” shall mean a generation resource located outside the metered boundaries of 
the PJM Region. 
 
Facilities Study: 
 
“Facilities Study” shall be an engineering study conducted by the Transmission Provider (in 
coordination with the affected Transmission Owner(s)) to: (1) determine the required 
modifications to the Transmission Provider’s Transmission System necessary to implement the 
conclusions of the System Impact Study; and (2) complete any additional studies or analyses 
documented in the System Impact Study or required by PJM Manuals, and determine the 
required modifications to the Transmission Provider’s Transmission System based on the 
conclusions of such additional studies.  The Facilities Study shall include the cost and scheduled 
completion date for such modifications, that will be required to provide the requested 
transmission service or to accommodate a New Service Request.  As used in the Interconnection

Service Agreement or Construction Service Agreement, Facilities Study shall mean that certain 
Facilities Study conducted by Transmission Provider (or at its direction) to determine the design 
and specification of the Customer Funded Upgrades necessary to accommodate the New Service 
Customer’s New Service Request in accordance with Tariff, Part VI, section 207.  
 
Fast-Start Resource:  
 
“Fast-Start Resource” shall have the meaning set forth in Tariff, Attachment K-Appendix, 
section 2.2A 
 
Federal Power Act: 
 
“Federal Power Act” shall mean the Federal Power Act, as amended, 16 U.S.C. §§ 791a, et seq. 
 
FERC or Commission: 
 
“FERC” or “Commission” shall mean the Federal Energy Regulatory Commission or any 
successor federal agency, commission or department exercising jurisdiction over the Tariff, 
Operating Agreement and Reliability Assurance Agreement. 
 
FERC Market Rules: 
 
 “FERC Market Rules” mean the market behavior rules and the prohibition against electric 
energy market manipulation codified by the Commission in its Rules and Regulations at 18 CFR 
§§ 1c.2 and 35.37, respectively; the Commission-approved PJM Market Rules and any related 
proscriptions or any successor rules that the Commission from time to time may issue, approve 
or otherwise establish.  
 
Final Offer: 
 
“Final Offer” shall mean the offer on which a resource was dispatched by the Office of the 
Interconnection for a particular clock hour for the Operating Day. 
 
Final RTO Unforced Capacity Obligation: 
 
“Final RTO Unforced Capacity Obligation” shall mean the capacity obligation for the PJM 
Region, determined in accordance with RAA, Schedule 8. 
 
Financial Close: 
 
“Financial Close” shall mean the Capacity Market Seller has demonstrated that the Capacity 
Market Seller or its agent has completed the act of executing the material contracts and/or other 
documents necessary to (1) authorize construction of the project and (2) establish the necessary 
funding for the project under the control of an independent third-party entity.  A sworn, notarized 
certification of an independent engineer certifying to such facts, and that the engineer has 
personal knowledge of, or has engaged in a diligent inquiry to determine, such facts, shall be

sufficient to make such demonstration.  For resources that do not have external financing, 
Financial Close shall mean the project has full funding available, and that the project has been 
duly authorized to proceed with full construction of the material portions of the project by the 
appropriate governing body of the company funding such project.  A sworn, notarized 
certification by an officer of such company certifying to such facts, and that the officer has 
personal knowledge of, or has engaged in a diligent inquiry to determine, such facts, shall be 
sufficient to make such demonstration. 
 
Financial Default: 
 
“Financial Default” shall mean (a) the failure of a Member or Transmission Customer to make 
any payment for obligations under the Agreements when due, including but not limited to an 
invoice payment that has not been cured or remedied after notice has been given and any cure 
period has elapsed, (b) a bankruptcy proceeding filed by a Member, Transmission Customer or 
its Guarantor, or filed against a Member, Transmission Customer or its Guarantor and to which 
the Member, Transmission Customer or Guarantor, as applicable, acquiesces or that is not 
dismissed within 60 days, (c) a Member, Transmission Customer or its Guarantor, if any, is 
unable to meet its financial obligations as they become due, or (d) a Merger Without Assumption 
occurs in respect of the Member, Transmission Customer or any Guarantor of such Member or 
Transmission Customer. 
 
Financial Transmission Right: 
 
“Financial Transmission Right” or “FTR” shall mean a right to receive Transmission Congestion 
Credits as specified in Operating Agreement, Schedule 1, section 5.2.2 and the parallel 
provisions of Tariff, Attachment K-Appendix, section 5.2.2. 
 
Financial Transmission Right Obligation: 
 
“Financial Transmission Right Obligation” shall mean a right to receive Transmission 
Congestion Credits as specified in Operating Agreement, Schedule 1, section 5.2.2(b), and the 
parallel provisions of Tariff, Attachment K-Appendix, section 5.2.2(b). 
 
Financial Transmission Right Option: 
 
“Financial Transmission Right Option” shall mean a right to receive Transmission Congestion 
Credits as specified in Operating Agreement, Schedule 1, section 5.2.2(c), and the parallel 
provisions of Tariff, Attachment K-Appendix, section 5.2.2(c). 
 
Firm Point-To-Point Transmission Service: 
 
“Firm Point-To-Point Transmission Service” shall mean Transmission Service under the Tariff, 
Part II, section 13 that is reserved and/or scheduled between specified Points of Receipt and 
Delivery pursuant to Tariff, Part II. 
 
Firm Transmission Feasibility Study:

“Firm Transmission Feasibility Study” shall mean a study conducted by the Transmission 
Provider in accordance with Tariff, Part II, section 19.3 and Tariff, Part III, section 32.3. 
 
Firm Transmission Withdrawal Rights: 
 
“Firm Transmission Withdrawal Rights” shall mean the rights to schedule energy and capacity 
withdrawals from a Point of Interconnection of a Merchant Transmission Facility with the 
Transmission System. Firm Transmission Withdrawal Rights may be awarded only to a 
Merchant D.C. Transmission Facility that connects the Transmission System with another 
control area. Withdrawals scheduled using Firm Transmission Withdrawal Rights have rights 
similar to those under Firm Point-to-Point Transmission Service. 
 
First Incremental Auction: 
 
“First Incremental Auction” shall mean an Incremental Auction conducted 20 months prior to the 
start of the Delivery Year to which it relates. 
 
Flexible Resource:   
“Flexible Resource” shall mean a generating resource that must have a combined Start-up Time 
and Notification Time of less than or equal to two hours; and a Minimum Run Time of less than 
or equal to two hours.   
Forecast Pool Requirement: 
 
“Forecast Pool Requirement” shall have the meaning specified in the Reliability Assurance 
Agreement.  
 
Foreign Guaranty: 
 
“Foreign Guaranty” shall mean a Corporate Guaranty provided by an Affiliate of a Participant 
that is domiciled in a foreign country, and meets all of the provisions of Tariff, Attachment Q. 
 
Form 715 Planning Criteria: 
 
“Form 715 Planning Criteria” shall have the same meaning provided in the Operating 
Agreement. 
 
Forward Daily Natural Gas Prices: 
 
“Forward Daily Natural Gas Prices” shall have the meaning provided in Tariff, Attachment DD, 
section 5.10(a)(v-1)(E).  
 
Forward Hourly Ancillary Services Prices:

“Forward Hourly Ancillary Services Prices” shall have the meaning provided in Tariff, 
Attachment DD, section 5.10(a)(v-1)(D).  
 
Forward Hourly LMPs:  
 
“Forward Hourly LMPs” shall have the meaning provided in Tariff, Attachment DD, section 
5.10(a)(v-1)(C). 
 
FTR Credit Limit:  
 
“FTR Credit Limit” shall mean the amount of credit established with PJMSettlement that an FTR 
Participant has specifically designated to be used for FTR activity in a specific customer account.  
Any such credit so set aside shall not be considered available to satisfy any other credit 
requirement the FTR Participant may have with PJMSettlement. 
 
FTR Credit Requirement: 
 
“FTR Credit Requirement” shall mean the amount of credit that a Participant must provide in 
order to support the FTR positions that it holds and/or for which it is bidding.  The FTR Credit 
Requirement shall not include months for which the invoicing has already been completed, 
provided that PJMSettlement shall have up to two Business Days following the date of the 
invoice completion to make such adjustments in its credit systems.  FTR Credit Requirements 
are calculated and applied separately for each separate customer account. 
 
FTR Flow Undiversified: 
 
“FTR Flow Undiversified” shall have the meaning established in Tariff, Attachment Q, section 
VI.C.6. 
 
FTR Historical Value: 
  
For each FTR for each month, “FTR Historical Value” shall mean the weighted average of  
historical values over three years for the FTR path using the following weightings:  50% - most 
recent year; 30% - second year; 20% - third year.   
 
FTR Holder: 
 
“FTR Holder” shall mean the PJM Member that has acquired and possesses an FTR. 
 
FTR Monthly Credit Requirement Contribution: 
 
For each FTR, for each month, ”FTR Monthly Credit Requirement Contribution” shall mean the 
total FTR cost for the month, prorated on a daily basis, less the FTR Historical Value for the 
month.  For cleared FTRs, this contribution may be negative; prior to clearing, FTRs with 
negative contribution shall be deemed to have zero contribution.

FTR Net Activity: 
  
“FTR Net Activity” shall mean the aggregate net value of the billing line items for auction 
revenue rights credits, FTR auction charges, FTR auction credits, and FTR congestion credits, 
and shall also include day-ahead and balancing/real-time congestion charges up to a maximum 
net value of the sum of the foregoing auction revenue rights credits, FTR auction charges, FTR 
auction credits and FTR congestion credits. 
 
FTR Participant: 
 
“FTR Participant” shall mean any Market Participant that provides or is required to provide 
Collateral in order to participate in PJM’s FTR market. 
 
FTR Portfolio Auction Value: 
 
“FTR Portfolio Auction Value” shall mean for each customer account of a Market Participant, 
the sum, calculated on a monthly basis, across all FTRs, of the FTR price times the FTR volume 
in MW.  
 
Fuel Cost Policy: 
 
“Fuel Cost Policy” shall mean the document provided by a Market Seller to PJM and the Market 
Monitoring Unit in accordance with PJM Manual 15 and Operating Agreement, Schedule 2, 
which documents the Market Seller’s method used to price fuel for calculation of the Market 
Seller’s cost-based offers for a generation resource.  
 
Full Notice to Proceed: 
 
“Full Notice to Proceed” shall mean that all material third party contractors have been given the 
notice to proceed with construction by the Capacity Market Seller or its agent, with a guaranteed 
completion date backed by liquidated damages.

Definitions – O – P - Q 
 
Obligation: 
  
“Obligation” shall mean all amounts owed to PJMSettlement for purchases from the PJM 
Markets, Transmission Service, (under both Tariff, Part II and Tariff, Part III), and other services 
or obligations pursuant to the Agreements.  In addition, aggregate amounts that will be owed to 
PJMSettlement in the future for capacity purchases within the PJM capacity markets will be 
added to this figure.  Should other markets be formed such that Participants may incur future 
Obligations in those markets, then the aggregate amount of those Obligations will also be added 
to the Net Obligation. 
 
Offer Data: 
 
“Offer Data” shall mean the scheduling, operations planning, dispatch, new resource, and other 
data and information necessary to schedule and dispatch generation resources and Demand 
Resource(s) for the provision of energy and other services and the maintenance of the reliability 
and security of the Transmission System in the PJM Region, and specified for submission to the 
PJM Interchange Energy Market for such purposes by the Office of the Interconnection. 
 
Office of the Interconnection: 
 
“Office of the Interconnection” shall mean the employees and agents of PJM Interconnection, 
L.L.C. subject to the supervision and oversight of the PJM Board, acting pursuant to the 
Operating Agreement. 
 
Office of the Interconnection Control Center: 
 
“Office of the Interconnection Control Center” shall mean the equipment, facilities and 
personnel used by the Office of the Interconnection to coordinate and direct the operation of the 
PJM Region and to administer the PJM Interchange Energy Market, including facilities and 
equipment used to communicate and coordinate with the Market Participants in connection with 
transactions in the PJM Interchange Energy Market or the operation of the PJM Region. 
 
On-Site Generators: 
 
“On-Site Generators” shall mean generation facilities or portions of a generation facility 
(including Behind The Meter Generation) that (i) are not Generation Capacity Resources, (ii) are 
not injecting into the grid for the portion of a generation facility that participates as a Demand 
Resource or as an Economic Load Response Participant unless permitted as an Economic Load 
Response Regulation Only Participant, (iii) are either synchronized or non-synchronized to the 
Transmission System, and (iv) can be used to reduce demand for the purpose of participating in 
the PJM Interchange Energy Market. 
 
Open Access Same-Time Information System (OASIS) or PJM Open Access Same-Time 
Information System:

“Open Access Same-Time Information System,” “PJM Open Access Same-Time Information 
System” or “OASIS” shall mean the electronic communication and information system and 
standards of conduct contained in Part 37 and Part 38 of the Commission’s regulations and all 
additional requirements implemented by subsequent Commission orders dealing with OASIS for 
the collection and dissemination of information about transmission services in the PJM Region, 
established and operated by the Office of the Interconnection in accordance with FERC 
standards and requirements. 
 
Open-Loop Hybrid Resource: 
 
“Open-Loop Hybrid Resource” shall mean a Hybrid Resource with a storage component that 
operates by charging its storage component from the grid. 
 
Operating Agreement of the PJM Interconnection, L.L.C., Operating Agreement or PJM 
Operating Agreement: 
 
“Operating Agreement of the PJM Interconnection, L.L.C.,”  “Operating Agreement” or “PJM 
Operating Agreement” shall mean the Amended and Restated Operating Agreement of PJM 
Interconnection, L.L.C. dated as of April 1, 1997 and as amended and restated as of June 2, 
1997, including all Schedules, Exhibits, Appendices, addenda or supplements hereto, as amended 
from time to time thereafter, among the Members of the PJM Interconnection, L.L.C., on file 
with the Commission. 
 
Operating Day: 
 
“Operating Day” shall mean the daily 24 hour period beginning at midnight for which 
transactions on the PJM Interchange Energy Market are scheduled. 
 
Operating Margin: 
 
“Operating Margin” shall mean the incremental adjustments, measured in megawatts, required in 
PJM Region operations in order to accommodate, on a first contingency basis, an operating 
contingency in the PJM Region resulting from operations in an interconnected Control Area.  
Such adjustments may result in constraints causing Transmission Congestion Charges, or may 
result in Ancillary Services charges pursuant to the PJM Tariff. 
 
Operating Margin Customer: 
 
“Operating Margin Customer” shall mean a Control Area purchasing Operating Margin pursuant 
to an agreement between such other Control Area and the LLC. 
 
Operating Reserve Demand Curve: 
 
“Operating Reserve Demand Curve” shall mean a curve with prices on the y-axis and megawatts 
on the x-axis, which defines the relationship between each incremental megawatt of reserves that

can be used to meet a given reserve requirement. 
 
Operationally Deliverable: 
 
“Operationally Deliverable” shall mean, as determined by the Office of the Interconnection, that 
there are no operational conditions, arrangements or limitations experienced or required that 
threaten, impair or degrade effectuation or maintenance of deliverability of capacity or energy 
from the external Generation Capacity Resource to loads in the PJM Region in a manner 
comparable to the deliverability of capacity or energy to such loads from Generation Capacity 
Resources located inside the metered boundaries of the PJM Region, including, without 
limitation, an identified need by an external Balancing Authority Area for a remedial action 
scheme or manual generation trip protocol, transmission facility switching arrangements  that 
would have the effect of radializing load, or excessive or unacceptable frequency of regional 
reliability limit violations or (outside an interregional agreed congestion management process) of 
local reliability dispatch instructions and commitments. 
 
Opportunity Cost: 
 
“Opportunity Cost” shall mean a component of the Market Seller Offer Cap calculated in 
accordance with Tariff, Attachment DD, section 6. 
 
OPSI Advisory Committee: 
 
“OPSI Advisory Committee” shall mean the committee established under Tariff, Attachment M, 
section III.G. 
 
Option to Build: 
 
“Option to Build” shall mean the option of the New Service Customer to build certain Customer-
Funded Upgrades, as set forth in, and subject to the terms of, the Construction Service 
Agreement. 
 
Optional Interconnection Study: 
 
“Optional Interconnection Study” shall mean a sensitivity analysis of an Interconnection Request 
based on assumptions specified by the Interconnection Customer in the Optional Interconnection 
Study Agreement. 
 
Optional Interconnection Study Agreement: 
 
“Optional Interconnection Study Agreement” shall mean the form of agreement for preparation 
of an Optional Interconnection Study, as set forth in Tariff, Attachment N-3. 
 
Part I:

“Part I” shall mean the Tariff Definitions and Common Service Provisions contained in Tariff, 
Part I, sections 1 through 12A. 
 
Part II: 
 
“Part II” shall mean Tariff, Part II, sections 13 through 27A pertaining to Point-To-Point 
Transmission Service in conjunction with the applicable Common Service Provisions of Tariff, 
Part I and appropriate Schedules and Attachments. 
 
Part III: 
 
“Part III” shall mean Tariff, Part III, sections 28 through 35 pertaining to Network Integration 
Transmission Service in conjunction with the applicable Common Service Provisions of Tariff, 
Part I and appropriate Schedules and Attachments. 
 
Part IV: 
 
“Part IV” shall mean Tariff, Part IV, sections 36 through 112C pertaining to generation or 
merchant transmission interconnection to the Transmission System in conjunction with the 
applicable Common Service Provisions of Tariff, Part I and appropriate Schedules and 
Attachments. 
 
Part V: 
 
“Part V” shall mean Tariff, Part V, sections 113 through 122 pertaining to the deactivation of 
generating units in conjunction with the applicable Common Service Provisions of Tariff, Part I 
and appropriate Schedules and Attachments. 
 
Part VI: 
 
“Part VI” shall mean Tariff, Part VI, sections 200 through 237 pertaining to the queuing, study, 
and agreements relating to New Service Requests, and the rights associated with Customer-
Funded Upgrades in conjunction with the applicable Common Service Provisions of Tariff, Part I 
and appropriate Schedules and Attachments. 
 
Participant: 
  
“Participant” shall mean a Market Participant and/or Transmission Customer and/or Applicant 
requesting to be an active Market Participant and/or Transmission Customer. 
 
Parties: 
 
“Parties” shall mean the Transmission Provider, as administrator of the Tariff, and the 
Transmission Customer receiving service under the Tariff.  PJMSettlement shall be the 
Counterparty to Transmission Customers.

Peak-Hour Dispatch: 
 
“Peak-Hour Dispatch” shall mean, for purposes of calculating the Energy and Ancillary Services 
Revenue Offset under Tariff, Attachment DD, section 5, an assumption, as more fully set forth in 
the PJM Manuals, that the Reference Resource is committed in the Day-ahead Energy Market in 
four distinct blocks of four hours of continuous output for each block from the peak-hour period 
beginning with the hour ending 0800 EPT through to the hour ending 2300 EPT for any day 
when the average day-ahead LMP for the area for which the Net Cost of New Entry is being 
determined is greater than, or equal to, the cost to generate (including the cost for a complete 
start and shutdown cycle), plus 10% of such costs only for the 2022/2023 Delivery Year, for at 
least two hours during each four-hour block, where such blocks shall be assumed to be  
committed independently; provided that, if there are not at least two economic hours in any given 
four-hour block, then the Reference Resource shall be assumed not to be committed for such 
block; and to the extent not committed in any such block in the Day-ahead Energy Market under 
the above conditions based on Day-Ahead LMPs, is dispatched in the Real-time Energy Market 
for such block if the Real-Time LMP is greater than or equal to the cost to generate, plus 10% of 
such costs only for the 2022/2023 Delivery Year, under the same conditions as described above 
for the Day-ahead Energy Market. 
 
Peak Market Activity:   
 
“Peak Market Activity” shall mean a measure of exposure for which credit is required, calculated 
in accordance with Tariff, Attachment Q, section VII.A.  
 
Peak Market Activity Shortfall: 
 
“Peak Market Activity Shortfall” shall mean, for any given week, the amount by which a 
Participant’s current Peak Market Activity exceeds such Participant’s Peak Market Activity 
credit requirement from the prior week. 
 
Peak Market Activity Surplus: 
 
“Peak Market Activity Surplus” shall mean, for any given week, the amount by which a 
Participant’s Peak Market Activity credit requirement from the prior week exceeds such 
Participant’s current Peak Market Activity. 
 
Peak Season: 
 
“Peak Season” shall mean the weeks containing the 24th through 36th Wednesdays of the 
calendar year.  Each such week shall begin on a Monday and end on the following Sunday, 
except for the week containing the 36th Wednesday, which shall end on the following Friday. 
 
Percentage Internal Resources Required: 
 
“Percentage Internal Resources Required” shall have the meaning specified in the Reliability 
Assurance Agreement.

Performance Assessment Interval: 
 
“Performance Assessment Interval” shall mean each Real-time Settlement Interval for which an 
Emergency Action has been declared by the Office of the Interconnection, provided, however, 
that Performance Assessment Intervals for a Base Capacity Resource shall not include any 
intervals outside the calendar months of June through September. 
 
Permissible Technological Advancement: 
 
“Permissible Technological Advancement” shall mean a proposed technological change such as 
an advancement to turbines, inverters, plant supervisory controls or other similar advancements 
to the technology proposed in the Interconnection Request that is submitted to the Transmission 
Provider no later than the return of an executed Facilities Study Agreement (or, if a Facilities 
Study is not required, prior to the return of an executed Interconnection Service Agreement).  
Provided such change may not:  (i) increase the capability of the Generating Facility as specified 
in the original Interconnection Request; (ii) represent a different fuel type from the original 
Interconnection Request; or (iii) cause any material adverse impact(s) on the Transmission 
System with regard to short circuit capability limits, steady-state thermal and voltage limits, or 
dynamic system stability and response.  If the proposed technological advancement is a 
Permissible Technological Advancement, no additional study will be necessary and the proposed 
technological advancement will not be considered a Material Modification. 
 
PJM:   
 
“PJM” shall mean PJM Interconnection, L.L.C., including the Office of the Interconnection as 
referenced in the PJM Operating Agreement.  When such term is being used in the RAA it shall 
also include the PJM Board. 
 
PJM Administrative Service: 
 
“PJM Administrative Service” shall mean the services provided by PJM pursuant to Tariff, 
Schedule 9. 
 
PJM Board: 
 
“PJM Board” shall mean the Board of Managers of the LLC, acting pursuant to the Operating 
Agreement except when such term is being used in Tariff, Attachment M, in which case PJM 
Board shall mean the Board of Managers of PJM or its designated representative, exclusive of 
any members of PJM Management. 
 
PJM Control Area: 
 
“PJM Control Area” shall mean the Control Area recognized by NERC as the PJM Control Area. 
 
PJM Entities:

“PJM Entities” shall mean PJM, including the Market Monitoring Unit, the PJM Board, and 
PJM’s officers, employees, representatives, advisors, contractors, and consultants. 
 
PJM Interchange: 
 
“PJM Interchange” shall mean the following, as determined in accordance with the Operating 
Agreement and Tariff: (a) for a Market Participant that is a Network Service User, the amount by 
which its interval Equivalent Load exceeds, or is exceeded by, the sum of the interval outputs of 
its operating generating resources; or (b) for a Market Participant that is not a Network Service 
User, the amount of its Spot Market Backup; or (c) the interval scheduled deliveries of Spot 
Market Energy by a Market Seller from an External Resource; or (d) the interval net metered 
output of any other Market Seller; or (e) the interval scheduled deliveries of Spot Market Energy 
to an External Market Buyer; or (f) the inteval scheduled deliveries to an Internal Market Buyer 
that is not a Network Service User. 
 
PJM Interchange Energy Market: 
 
“PJM Interchange Energy Market” shall mean the regional competitive market administered by 
the Office of the Interconnection for the purchase and sale of spot electric energy at wholesale in 
interstate commerce and related services established pursuant to Operating Agreement, Schedule 
1, and the parallel provisions of Tariff, Attachment K – Appendix. 
 
PJM Interchange Export: 
 
“PJM Interchange Export” shall mean the following, as determined in accordance with the 
Operating Agreement and Tariff:  (a) for a Market Participant that is a Network Service User, the 
amount by which its interval Equivalent Load is exceeded by the sum of the inteval outputs of its 
operating generating resources; or (b) for a Market Participant that is not a Network Service 
User, the amount of its Spot Market Backup sales; or (c) the interval scheduled deliveries of Spot 
Market Energy by a Market Seller from an External Resource; or (d) the interval net metered 
output of any other Market Seller. 
 
PJM Interchange Import: 
 
“PJM Interchange Import” shall mean the following, as determined in accordance with the 
Operating Agreement and Tariff:  (a) for a Market Participant that is a Network Service User, the 
amount by which its interval Equivalent Load exceeds the sum of the interval outputs of its 
operating generating resources; or (b) for a Market Participant that is not a Network Service 
User, the amount of its Spot Market Backup purchases; or (c) the interval scheduled deliveries of 
Spot Market Energy to an External Market Buyer; or (d) the interval scheduled deliveries to an 
Internal Market Buyer that is not a Network Service User. 
 
PJM Liaison: 
 
“PJM Liaison” shall mean the liaison established under Tariff, Attachment M, section III.I.

PJM Management: 
 
“PJM Management” shall mean the officers, executives, supervisors and employee managers of 
PJM. 
 
PJM Manuals: 
 
“PJM Manuals” shall mean the instructions, rules, procedures and guidelines established by the 
Office of the Interconnection for the operation, planning, and accounting requirements of the 
PJM Region and the PJM Interchange Energy Market. 
 
PJM Markets: 
 
“PJM Markets” shall mean the PJM Interchange Energy Market, capacity markets, including the 
RPM auctions, and any other market operated by PJM, together with all bilateral or other 
wholesale electric power and energy transactions, capacity transactions, ancillary services 
transactions (including black start service), transmission transactions, Financial Transmission 
Rights transactions, or transactions in any other market operated under the Agreements within 
the PJM Region, wherein Market Participants may incur Obligations to PJM and/or 
PJMSettlement. 
 
PJM Market Rules: 
 
“PJM Market Rules” shall mean the rules, standards, procedures, and practices of the PJM 
Markets set forth in the PJM Tariff, the PJM Operating Agreement, the PJM Reliability 
Assurance Agreement, the PJM Consolidated Transmission Owners Agreement, the PJM 
Manuals, the PJM Regional Practices Document, the PJM-Midwest Independent Transmission 
System Operator Joint Operating Agreement or any other document setting forth market rules. 
 
PJM Net Assets: 
 
“PJM Net Assets” shall mean the total assets per PJM’s consolidated quarterly or year-end 
financial statements most recently issued as of the date of the receipt of written notice of a claim 
less amounts for which PJM is acting as a temporary custodian on behalf of its Members, 
transmission developers/Designated Entities, and generation developers, including, but not 
limited to, cash deposits related to credit requirement compliance, study and/or interconnection 
receivables, member prepayments, invoiced amounts collected from Net Buyers but have not yet 
been paid to Net Sellers, and excess congestion (as described in Operating Agreement, Schedule 
1, section 5.2.6, and the parallel provisions of Tariff, Attachment K-Appendix, section 5.2.6). 
 
PJM Region: 
 
“PJM Region” shall have the meaning specified in the Operating Agreement.  
 
PJM Regional Practices Document:

“PJM Regional Practices Document” shall mean the document of that title that compiles and 
describes the practices in the PJM Markets and that is made available in hard copy and on the 
Internet. 
 
PJM Region Installed Reserve Margin: 
 
“PJM Region Installed Reserve Margin” shall mean the percent installed reserve margin for the 
PJM Region required pursuant to RAA, Schedule 4.1, as approved by the PJM Board. 
 
PJM Region Peak Load Forecast: 
 
“PJM Region Peak Load Forecast” shall mean the peak load forecast used by the Office of the 
Interconnection in determining the PJM Region Reliability Requirement, and shall be determined 
on both a preliminary and final basis as set forth in Tariff, Attachment DD, section 5.   
 
PJM Region Reliability Requirement:  
 
“PJM Region Reliability Requirement” shall mean, for purposes of the Base Residual Auction, 
the Forecast Pool Requirement multiplied by the Preliminary PJM Region Peak Load Forecast, 
less the sum of all Preliminary Unforced Capacity Obligations of FRR Entities in the PJM 
Region; and, for purposes of the  Incremental Auctions, the Forecast Pool Requirement 
multiplied by the updated PJM Region Peak Load Forecast, less the sum of all updated Unforced 
Capacity Obligations of FRR Entities in the PJM Region. 
 
PJMSettlement:   
 
“PJM Settlement” or “PJM Settlement, Inc.” shall mean PJM Settlement, Inc. (or its successor), 
established by PJM as set forth in Operaitng Agreement, section 3.3. 
 
PJM Tariff, Tariff, O.A.T.T., OATT or PJM Open Access Transmission Tariff: 
 
“PJM Tariff,” “Tariff,” “O.A.T.T.,” “OATT,” or “PJM Open Access Transmission Tariff” shall 
mean that certain PJM Open Access Transmission Tariff, including any schedules, appendices or 
exhibits attached thereto, on file with FERC and as amended from time to time thereafter. 
 
Plan: 
 
“Plan” shall mean the PJM market monitoring plan set forth in Tariff, Attachment M. 
 
Planned Demand Resource: 
 
“Planned Demand Resource” shall have the meaning specified in the Reliability Assurance 
Agreement. 
 
Planned External Generation Capacity Resource:

“Planned External Generation Capacity Resource” shall have the meaning specified in the 
Reliability Assurance Agreement. 
 
Planned Generation Capacity Resource: 
 
“Planned Generation Capacity Resource” shall have the meaning specified in the Reliability 
Assurance Agreement. 
 
Planning Period: 
 
“Planning Period” shall mean the 12 moths beginning June 1 and extending through May 31 of 
the following year, or such other period approved by the Members Committee. 
 
Planning Period Balance: 
 
“Planning Period Balance” shall mean the entire period of time remaining in the Planning Period 
following the month that a monthly auction is conducted.  
 
Planning Period Quarter: 
 
“Planning Period Quarter” shall mean any of the following three month periods in the Planning 
Period: June, July and August; September, October and November; December, January and 
February; or March, April and May. 
 
Point(s) of Delivery: 
 
“Point(s) of Delivery” shall mean the point(s) on the Transmission Provider’s Transmission 
System where capacity and energy transmitted by the Transmission Provider will be made 
available to the Receiving Party under Tariff, Part II.  The Point(s) of Delivery shall be specified 
in the Service Agreement for Long-Term Firm Point-To-Point Transmission Service. 
 
Point of Interconnection: 
 
“Point of Interconnection” shall mean the point or points where the Customer Interconnection 
Facilities interconnect with the Transmission Owner Interconnection Facilities or the 
Transmission System. 
 
Point(s) of Receipt: 
 
“Point(s) of Receipt” shall mean point(s) of interconnection on the Transmission Provider’s 
Transmission System where capacity and energy will be made available to the Transmission 
Provider by the Delivering Party under Tariff, Part II.  The Point(s) of Receipt shall be specified 
in the Service Agreement for Long-Term Firm Point-To-Point Transmission Service. 
 
Point-To-Point Transmission Service:

“Point-To-Point Transmission Service shall mean the reservation and transmission of capacity 
and energy on either a firm or non-firm basis from the Point(s) of Receipt to the Point(s) of 
Delivery under Tariff, Part II. 
 
Power Purchaser: 
 
“Power Purchaser” shall mean the entity that is purchasing the capacity and energy to be 
transmitted under the Tariff. 
 
PRD Curve: 
 
“PRD Curve” shall have the meaning provided in the Reliability Assurance Agreement. 
 
PRD Provider: 
 
“PRD Provider” shall have the meaning provided in the Reliability Assurance Agreement. 
 
PRD Reservation Price: 
 
“PRD Reservation” Price shall have the meaning provided in the Reliability Assurance 
Agreement. 
 
PRD Substation:   
 
“PRD Substation” shall have the meaning provided in the Reliability Assurance Agreement. 
 
Pre-Confirmed Application: 
 
“Pre-Confirmed Application” shall be an Application that commits the Eligible Customer to 
execute a Service Agreement upon receipt of notification that the Transmission Provider can 
provide the requested Transmission Service. 
 
Pre-Emergency Load Response Program: 
 
“Pre-Emergency Load Response Program” shall be the program by which Curtailment Service 
Providers may be compensated by PJM for Demand Resources that will reduce load when 
dispatched by PJM during pre-emergency conditions, and is described in Operating Agreement, 
Schedule 1, section 8 and the parallel provisions of Tariff, Attachment K-Appendix, section 8.  
 
Pre-Expansion PJM Zones: 
 
“Pre-Expansion PJM Zones” shall be zones included in the Tariff, along with applicable 
Schedules and Attachments, for certain Transmission Owners – Atlantic City Electric Company, 
Baltimore Gas and Electric Company, Delmarva Power and Light Company, Jersey Central 
Power and Light Company, Mid-Atlantic Interstate Transmission, LLC (“MAIT”) (MAIT owns 
and operates the transmission facilities in the Metropolitan Edison Company Zone and the

Pennsylvania Electric Company Zone), PECO Energy Company, Pennsylvania Power & Light 
Group, Potomac Electric Power Company, Public Service Electric and Gas Company, Allegheny 
Power, and Rockland Electric Company. 
 
Price Responsive Demand: 
 
“Price Responsive Demand” shall have the meaning provided in the Reliability Assurance 
Agreement. 
 
Primary Reserve: 
 
“Primary Reserve” shall mean the total reserve capability of generation resources that can be 
converted fully into energy or Economic Load Response Participant resources whose demand 
can be reduced within ten minutes of a request from the Office of the Interconnection dispatcher, 
and is comprised of both Synchronized Reserve and Non-Synchronized Reserve. 
 
Primary Reserve Alert 
 
“Primary Reserve Alert” shall mean a notification from PJM to alert Members of an anticipated 
shortage of Operating Reserve capacity for a future critical period. 
 
Primary Reserve Requirement: 
 
“Primary Reserve Requirement” shall mean the megawatts required to be maintained in a 
Reserve Zone or Reserve Sub-zone as Primary Reserve absent any increase to account for 
additional reserves scheduled to address operational uncertainty.  The Primary Reserve 
Requirement is calculated in accordance with the PJM Manuals.  The requirement can be 
satisfied by any combination of Synchronized Reserve or Non-Synchronized Reserve resources. 
 
Principal: 
 
“Principal” shall mean (i) all natural persons who Control Corporate Level Strategy for the 
Participant, which shall include a chief executive officer, managing member (or equivalent 
positions regardless of title) and members of a board of directors or board of managers; (ii) the 
chief legal officer or general counsel (or equivalent position regardless of title); (iii) the natural 
person who Controls the financial affairs and investments of the Participant, which shall include 
a chief financial officer (or equivalent position regardless of title); (iv) the natural person who 
Controls the Participant’s management of commodity and derivatives market risks, which shall 
include a chief risk officer (or equivalent position regardless of title); (v) the natural person who 
Controls the Participant’s transactions in the applicable PJM Markets (regardless of title); and 
(vi) all Beneficial Owners.  
 
“Control,” as that term is used in this definition, refers to possession of the power to direct the 
management or policies of an entity.

“Corporate Level Strategy,” as that term is used in this definition, refers to the highest-level 
strategy of an entity, focused on the entity’s overall direction rather than the day-to-day 
operations of the entity. 
 
“Beneficial Owner,” as that term is used in this definition, means a natural person who, directly 
or indirectly, alone or together with such person’s Family Members, owns, controls, or holds 
with power to vote 10 percent or more of the outstanding securities of the Participant.  
 
“Family Member,” as that term is used in this definition of “Beneficial Owner,” means a spouse, 
domestic partner, parent, child, or sibling.  
 
For purposes of trusts with, directly or indirectly, 10 percent or more of the outstanding 
securities of the Participant as described above, the following are Beneficial Owners: (a) a 
natural person trustee; (b) a natural person with the authority to dispose of the trust assets; (c) a 
natural person grantor or settlor who has the right to revoke the trust or otherwise withdraw the 
assets of the trust; and (d) a natural person beneficiary who is the sole permissible recipient of 
income and principal from the trust or has the right to demand a distribution of or withdraw 
substantially all of the assets from the trust. 
 
If, due to the Participant’s business enterprise, structure or otherwise, a function described in 
clauses (i) through (v) above is performed by a natural person or entity separate from the 
Participant (such as a risk management department in an affiliate, or a director or manager at an 
entity that controls or invests in the Participant), then for that Participant the term Principal shall 
mean that natural person, or the senior officer or manager of that entity, that performs such 
function. 
 
Prior CIL Exception External Resource: 
 
“Prior CIL Exception External Resource” shall mean an external Generation Capacity Resource 
for which (1) a Capacity Market Seller had, prior to May 9, 2017, cleared a Sell Offer in an RPM 
Auction under the exception provided to the definition of Capacity Import Limit as set forth in 
RAA, Article I or (2) an FRR Entity committed, prior to May 9, 2017, in an FRR Capacity Plan 
under the exception provided in the definition of Capacity Import Limit.  In the event only a 
portion (in MW) of an external Generation Capacity Resource has a Pseudo-Tie into the PJM 
Region, that portion of the external Generation Capacity Resource, which can include up to the 
maximum megawatt amount cleared in any prior RPM auction or committed in an FRR Capacity 
Plan (and no other portion thereof) is eligible for treatment as a Prior CIL Exception External 
Resource if such portion satisfies the requirements of the first sentence of this definition. 
 
Project Financing: 
 
“Project Financing” shall mean:  (a) one or more loans, leases, equity and/or debt financings, 
together with all modifications, renewals, supplements, substitutions and replacements thereof, 
the proceeds of which are used to finance or refinance the costs of the Customer Facility, any 
alteration, expansion or improvement to the Customer Facility, the purchase and sale of the 
Customer Facility or the operation of the Customer Facility; (b) a power purchase agreement

pursuant to which Interconnection Customer’s obligations are secured by a mortgage or other 
lien on the Customer Facility; or (c) loans and/or debt issues secured by the Customer Facility. 
 
Project Finance Entity: 
 
“Project Finance Entity” shall mean:  (a) a holder, trustee or agent for holders, of any component 
of Project Financing; or (b) any purchaser of capacity and/or energy produced by the Customer 
Facility to which Interconnection Customer has granted a mortgage or other lien as security for 
some or all of Interconnection Customer’s obligations under the corresponding power purchase 
agreement. 
 
Projected EAS Dispatch: 
 
“Projected EAS Dispatch” shall mean, for purposes of calculating the Net Energy and Ancillary 
Services Revenue Offset, a simulated dispatch with the objective of committing and dispatching 
a resource for the purpose of maximizing its net revenues. The calculation shall take inputs 
including Forward Hourly LMPs, Forward Hourly Ancillary Service Prices, and Forward Daily 
Natural Gas Prices or forecasted fuel prices, as applicable, in addition to the operating 
parameters and costs of the specific resource, including the cost emission allowances. Using 
operating parameters, forward or forecasted fuel prices, as applicable and other cost pricing 
inputs, a composite, cost-based energy offer is created for the resource such that its commitment 
and dispatch is co-optimized between energy and ancillary services in the Day-Ahead Energy 
Market and then the Real-Time Energy Market considering the electricity and ancillary service 
price inputs. In the Real-Time Energy Market co-optimization, the resource is assumed to be 
operating in the hours it was scheduled in the Day-Ahead Energy Market but is dispatched 
according to the real-time price inputs. In the hours where the resource was not committed in the 
Day-Ahead Market, the resource may be committed and dispatched in real-time only subject to 
the real-time electricity and ancillary service price inputs and the resource’s offer and operating 
parameters.  For combustion turbine units only, the cost-based energy offer will include a 10 
percent adder only for the 2022/2023 Delivery Year. 
 
Projected PJM Market Revenues: 
 
“Projected PJM Market Revenues” shall mean a component of the Market Seller Offer Cap 
calculated in accordance with Tariff, Attachment DD, section 6. 
 
Proportional Multi-Driver Project: 
 
“Proportional Multi-Driver Project” shall have the same meaning provided in the Operating 
Agreement. 
 
Provisional Interconnection Service: 
 
“Provisional Interconnection Service” shall mean interconnection service provided by 
Transmission Provider associated with interconnecting the Interconnection Customer’s 
Generating Facility to Transmission Provider’s Transmission System and enabling that

Transmission System to receive electric energy and capacity from the Generating Facility at the 
Point of Interconnection, pursuant to the terms of the Interconnection Service Agreement and, if 
applicable, the Tariff. 
 
Pseudo-Tie: 
 
“Pseudo-Tie” shall have the same meaning provided in the Operating Agreement. 
 
Public Policy Objectives: 
 
“Public Policy Objectives” shall have the same meaning provided in the Operating Agreement. 
 
Public Policy Requirements: 
 
“Public Policy Requirements” shall have the same meaning provided in the Operating 
Agreement. 
 
Qualifying RBP Offset UCAP MW: 
 
“Qualifying RBP Offset UCAP MW” shall mean unforced capacity that: (i) pursuant to Tariff, 
Attachment DD, section 18.2, has not received an RPM commitment or been committed in an 
FRR Plan as of the commencement of the Reliability Backstop Procurement, (ii) is supplied by 
eligible Capacity Resources in accordance with Tariff, Attachment DD, section 18.2(b), and (iii) 
is supported by evidence, in accordance with Tariff, Attachment DD, section 18.2(c). 
 
Qualifying Transmission Upgrade: 
 
“Qualifying Transmission Upgrade” shall mean a proposed enhancement or addition to the 
Transmission System that: (a) will increase the Capacity Emergency Transfer Limit into an LDA 
by a megawatt quantity certified by the Office of the Interconnection; (b) the Office of the 
Interconnection has determined will be in service on or before the commencement of the first 
Delivery Year for which such upgrade is the subject of a Sell Offer in the Base Residual 
Auction; (c) is the subject of a Facilities Study Agreement executed before the conduct of the 
Base Residual Auction for such Delivery Year and (d) a New Service Customer is obligated to 
fund through a rate or charge specific to such facility or upgrade. 
 
Queue Position: 
 
“Queue Position” shall mean the priority assigned to an Interconnection Request, a Completed 
Application, or an Upgrade Request pursuant to applicable provisions of Tariff, Part VI.

Definitions – R - S 
 
Ramping Capability: 
 
“Ramping Capability” shall mean the sustained rate of change of generator output, in megawatts 
per minute. 
 
Rating Agency: 
 
“Rating Agency” shall mean a Nationally Recognized Statistical Rating Organization that 
assesses the financial condition, strength and stability of companies and governmental entities 
and their ability to timely make principal and interest payments on their debts and the likelihood 
of default, and assigns a rating that reflects its assessment of the ability of the company or 
governmental entity to make the debt payments. 
 
RBP Charges: 
 
“RBP Charges” shall mean the $/day value of the total RBP Settlement Credits, positive or 
negative, of all committed RBP Resources across the PJM Region. 
 
RBP Collateral: 
 
“RBP Collateral” shall mean: either (1) a cash deposit, including any interest thereon, or (2) a 
letter of credit issued for the benefit of PJM or PJMSettlement, in an amount and form 
determined by and acceptable to PJM or PJMSettlement. 
 
RBP Obligation: 
 
“RBP Obligation” or “RBO” shall mean the state and/or RERRA-determined allocation of RBP 
UCAP MW to Load Serving Entities within each Electric Distributor’s zone/area. 
 
RBP Resources: 
 
“RBP Resources” shall mean generation resources, Energy Storage Resources, Demand 
Resources, or DER Aggregation Resources, as set forth in Tariff, Attachment DD, section 18.5, 
offered to provide RBP UCAP MW from the Reliability Backstop Procurement, in accordance 
with Tariff, Attachment DD, section 18. 
 
RBP Seller: 
 
“RBP Seller” shall mean an entity that owns or controls an RBP Resource that is offered into the 
Reliability Backstop Procurement. 
 
 
RBP Sell Offer:

“RBP Sell Offer” shall mean an offer to sell RBP Resources in the Reliability Backstop 
Procurement. 
 
RBP Settlement Credits: 
 
“RBP Settlement Credits” shall mean, for each day in the Delivery Year in the term of the 
Reliability Backstop Procurement commitment period, the $/day value that a resource committed 
in the Reliability Backstop Procurement receives as a contract for differences settlement in 
accordance with Tariff, Attachment DD, section 18.5(g). 
 
RBP UCAP MW: 
 
“RBP UCAP MW” shall mean unforced capacity that is eligible to be offered in the Reliability 
Backstop Procurement, in accordance with Tariff, Attachment DD, section 18. 
 
Real-time Congestion Price: 
 
“Real-time Congestion Price” shall mean the Congestion Price resulting from the Office of the 
Interconnection’s dispatch of the PJM Interchange Energy Market in the Operating Day. 
 
Real-time Loss Price: 
 
“Real-time Loss Price” shall mean the Loss Price resulting from the Office of the 
Interconnection’s dispatch of the PJM Interchange Energy Market in the Operating Day. 
 
Real-time Energy Market: 
 
“Real-time Energy Market” shall mean the purchase or sale of energy and payment of 
Transmission Congestion Charges for quantity deviations from the Day-ahead Energy Market in 
the Operating Day. 
 
Real-time Offer: 
 
“Real-time Offer” shall mean a new offer or an update to a Market Seller’s existing cost-based or 
market-based offer for a clock hour, submitted for use after the close of the Day-ahead Energy 
Market. 
 
Real-time Prices: 
 
“Real-time Prices” shall mean the Locational Marginal Prices resulting from the Office of the 
Interconnection’s dispatch of the PJM Interchange Energy Market in the Operating Day. 
 
Real-time Settlement Interval: 
 
“Real-time Settlement Interval” shall mean the interval used by settlements, which shall be every 
five minutes.

Real-time State of Charge: 
 
“Real-time State of Charge” shall mean the current State of Charge of an Energy Storage 
Resource Model Participant, measured in units of megawatt-hours. 
 
Real-time System Energy Price: 
 
“Real-time System Energy Price” shall mean the System Energy Price resulting from the Office 
of the Interconnection’s dispatch of the PJM Interchange Energy Market in the Operating Day. 
 
Reasonable Efforts: 
 
“Reasonable Efforts” shall mean, with respect to any action required to be made, attempted, or 
taken by an Interconnection Party or by a Construction Party under Tariff, Part IV or Tariff, Part 
VI, an Interconnection Service Agreement, or a Construction Service Agreement, such efforts as 
are timely and consistent with Good Utility Practice and with efforts that such party would 
undertake for the protection of its own interests. 
 
Receiving Party: 
 
“Receiving Party” shall mean the entity receiving the capacity and energy transmitted by the 
Transmission Provider to Point(s) of Delivery. 
 
Referral: 
 
“Referral” shall mean a formal report of the Market Monitoring Unit to the Commission for 
investigation of behavior of a Market Participant, of behavior of PJM, or of a market design 
flaw, pursuant to Tariff, Attachment M, section IV.I. 
 
Reference Resource: 
 
For Delivery Years up to and including the 2025/2026 Delivery Year, “Reference Resource” 
shall mean a combustion turbine generating station, configured with a single General Electric 
Frame 7HA turbine with evaporative cooling, Selective Catalytic Reduction technology, dual 
fuel capability, and a heat rate of 9.134 Mmbtu/ MWh.  For the 2026/2027 through and including 
the 2027/2028 Delivery Years, “Reference Resource” shall mean, for all CONE Areas, a 
combustion turbine generating station, configured with a single General Electric Frame 7HA 
turbine with evaporative cooling, Selective Catalytic Reduction technology, dual fuel capability, 
and a heat rate of 9.189 Mmbtu/MWh.  For the 2028/2029 Delivery Year and subsequent 
Delivery Years, “Reference Resource” shall mean a combustion turbine generation station, 
configured with a single 1x0 GE Frame 7HA.03 turbine with evaporative cooling, no inlet 
chillers, wet compression, Selective Catalytic Reduction technology, dual fuel capability, and a 
heat rate of 9.199 MMBtu/MWh. 
 
Regional Entity:

“Regional Entity” shall have the same meaning specified in the Operating Agreement. 
 
Regional Network Integration Transmission Service:  
 
“Regional Network Integration Transmission Service” shall mean firm transmission service 
taken by Network Customers that involves the delivery of energy and/or capacity from Network 
Resources physically interconnected to the Transmission Provider’s transmission system to 
Network Load physically interconnected to the Transmission Provider’s transmission system. 
 
Regional Transmission Expansion Plan: 
 
“Regional Transmission Expansion Plan” shall mean the plan prepared by the Office of the 
Interconnection pursuant to Operating Agreement, Schedule 6 for the enhancement and 
expansion of the Transmission System in order to meet the demands for firm transmission 
service in the PJM Region. 
 
Regional Transmission Group (RTG): 
 
“Regional Transmission Group” or “RTG” shall mean a voluntary organization of transmission 
owners, transmission users and other entities approved by the Commission to efficiently 
coordinate transmission planning (and expansion), operation and use on a regional (and 
interregional) basis. 
 
Regulation: 
 
“Regulation” shall mean the capability of a specific generation resource or Demand Resource 
with appropriate telecommunications, control and response capability to separately increase and 
decrease its output or adjust load in response to a regulating control signal, in accordance with 
the specifications in the PJM Manuals. 
 
Regulation Requirement: 
 
“Regulation Requirement” shall mean the required megawatts of performance-adjusted 
Regulation capability to be maintained in a Regulation Zone. The Regulation Requirement is 
defined as a set megawatt value by commitment interval and can increase to account for 
additional operational uncertainty, in accordance with the PJM Manuals. 
 
Regulation Zone: 
 
“Regulation Zone” shall mean any of those one or more geographic areas, each consisting of a 
combination of one or more Control Zone(s) as designated by the Office of the Interconnection 
in the PJM Manuals, relevant to provision of, and requirements for, regulation service. 
 
Relevant Electric Retail Regulatory Authority:

“Relevant Electric Retail Regulatory Authority” shall mean an entity that has jurisdiction over 
and establishes prices and policies for competition for providers of retail electric service to end-
customers, such as the city council for a municipal utility, the governing board of a cooperative 
utility, the state public utility commission or any other such entity. 
 
Reliability Assurance Agreement or PJM Reliability Assurance Agreement: 
 
“Reliability Assurance Agreement” or “PJM Reliability Assurance Agreement” shall mean that 
certain Reliability Assurance Agreement Among Load Serving Entities in the PJM Region, on 
file with FERC as PJM Interconnection L.L.C. Rate Schedule FERC No. 44, and as amended 
from time to time thereafter. 
 
Reliability Pricing Model Auction: 
 
“Reliability Pricing Model Auction” or “RPM Auction” shall mean the Base Residual Auction or 
any Incremental Auction. 
 
Required Transmission Enhancements: 
 
“Regional Transmission Enhancements” shall mean enhancements and expansions of the 
Transmission System that (1) a Regional Transmission Expansion Plan developed pursuant to 
Operating Agreement, Schedule 6 or (2) any joint planning or coordination agreement between 
PJM and another region or transmission planning authority set forth in Tariff, Schedule 12-
Appendix B (“Appendix B Agreement”) designates one or more of the Transmission Owner(s) to 
construct and own or finance.  Required Transmission Enhancements shall also include 
enhancements and expansions of facilities in another region or planning authority that meet the 
definition of transmission facilities pursuant to FERC’s Uniform System of Accounts or have 
been classified as transmission facilities in a ruling by FERC addressing such facilities 
constructed pursuant to an Appendix B Agreement cost responsibility for which has been 
assigned at least in part to PJM pursuant to such Appendix B Agreement.  
 
Reserved Capacity: 
 
“Reserved Capacity” shall mean the maximum amount of capacity and energy that the 
Transmission Provider agrees to transmit for the Transmission Customer over the Transmission 
Provider’s Transmission System between the Point(s) of Receipt and the Point(s) of Delivery 
under Tariff, Part II.  Reserved Capacity shall be expressed in terms of whole megawatts on a 
sixty (60) minute interval (commencing on the clock hour) basis. 
 
Reserve Penalty Factor: 
 
“Reserve Penalty Factor” shall mean the cost, in $/MWh, associated with being unable to meet a 
specific reserve requirement in a Reserve Zone or Reserve Sub-zone.  A Reserve Penalty Factor 
will be defined for each reserve requirement in a Reserve Zone or Reserve Sub-zone. 
 
Reserve Sub-zone:

“Reserve Sub-zone” shall mean any of those geographic areas wholly contained within a Reserve 
Zone, consisting of a combination of a portion of one or more Control Zone(s) as designated by 
the Office of the Interconnection in the PJM Manuals, relevant to provision of, and requirements 
for, reserve service. 
 
Reserve Zone: 
 
“Reserve Zone” shall mean any of those geographic areas consisting of a combination of one or 
more Control Zone(s), as designated by the Office of the Interconnection in the PJM Manuals, 
relevant to provision of, and requirements for, reserve service. 
 
Residual Auction Revenue Rights: 
 
“Residual Auction Revenue Rights” shall mean incremental stage 1 Auction Revenue Rights 
created within a Planning Period by an increase in transmission system capability, including the 
return to service of existing transmission capability, that was not modeled pursuant to Operating 
Agreement, Schedule 1, section 7.5 and the parallel provisions of  Tariff, Attachment K-
Appendix, section 7.5 in compliance with Operating Agreement, Schedule 1, section 7.4.2 (h) 
and the parallel provisions of Tariff, Attachment K-Appendix, section 7.4.2(h), and, if modeled, 
would have increased the amount of stage 1 Auction Revenue Rights allocated pursuant to 
Operating Agreement, Schedule 1, section 7.4.2 and the parallel provisions of Tariff, Attachment 
K-Appendix, section 7.4.2; provided that, the foregoing notwithstanding, Residual Auction 
Revenue Rights shall exclude: 1) Incremental Auction Revenue Rights allocated pursuant to 
Tariff, Part VI;  and 2) Auction Revenue Rights allocated to entities that are assigned cost 
responsibility pursuant to Operating Agreement, Schedule 6 for  transmission upgrades that 
create such rights. 
 
Residual Metered Load: 
 
“Residual Metered Load” shall mean all load remaining in an electric distribution company’s 
fully metered franchise area(s) or service territory(ies) after all nodally priced load of entities 
serving load in such area(s) or territory(ies) has been carved out. 
 
Resource Substitution Charge: 
 
“Resource Substitution Charge” shall mean a charge assessed on Capacity Market Buyers in an 
Incremental Auction to recover the cost of replacement Capacity Resources. 
 
Restricted Collateral: 
 
“Restricted Collateral” shall mean Collateral, held by PJM or PJMSettlement, which cannot be 
used, netted, credited or spent by the Participant to satisfy any other obligations. 
 
Revenue Data for Settlements:

“Revenue Data for Settlements” shall mean energy quantities used in accounting and billing as 
determined pursuant to Tariff, Attachment K-Appendix and the corresponding provisions of 
Operating Agreement, Schedule 1. 
 
RPM Seller Credit: 
  
“RPM Seller Credit” shall mean an additional form of Unsecured Credit defined in Tariff, 
Attachment Q, section VI. 
 
Scheduled Incremental Auctions: 
 
“Scheduled Incremental Auctions” shall refer to the First, Second, or Third Incremental Auction. 
 
Schedule of Work: 
 
“Schedule of Work” shall mean that schedule attached to the Interconnection Construction 
Service Agreement setting forth the timing of work to be performed by the Constructing Entity 
pursuant to the Interconnection Construction Service Agreement, based upon the Facilities Study 
and subject to modification, as required, in accordance with Transmission Provider’s scope 
change process for interconnection projects set forth in the PJM Manuals. 
 
Scope of Work: 
 
“Scope of Work” shall mean that scope of the work attached as a schedule to the Interconnection 
Construction Service Agreement and to be performed by the Constructing Entity(ies) pursuant to 
the Interconnection Construction Service Agreement, provided that such Scope of Work may be 
modified, as required, in accordance with Transmission Provider’s scope change process for 
interconnection projects set forth in the PJM Manuals. 
 
Seasonal Capacity Performance Resource: 
 
“Seasonal Capacity Performance Resource” shall have the same meaning specified in Tariff, 
Attachment DD, section 5.5A. 
 
Secondary Reserve:  
 
“Secondary Reserve” shall mean the reserve capability of generation resources that can be 
converted fully into energy or Economic Load Response Participant resources whose demand 
can be reduced within 30 minutes (less the capability of such resources to provide Primary 
Reserve), from the request of the Office of the Interconnection, regardless of whether the 
equipment providing the reserve is electrically synchronized to the Transmission System or not. 
 
Secondary Systems: 
 
“Secondary Systems” shall mean control or power circuits that operate below 600 volts, AC or 
DC, including, but not limited to, any hardware, control or protective devices, cables,

conductors, electric raceways, secondary equipment panels, transducers, batteries, chargers, and 
voltage and current transformers. 
 
Second Incremental Auction: 
 
“Second Incremental Auction” shall mean an Incremental Auction conducted ten months before 
the Delivery Year to which it relates.   
 
Security: 
 
“Security” shall mean the security provided by the New Service Customer pursuant to Tariff, 
section 212.4 or Tariff, Part VI, section 213.4 to secure the New Service Customer’s 
responsibility for Costs under the Interconnection Service Agreement or Upgrade Construction 
Service Agreement and Tariff, Part VI, section 217.  
 
Segment:  
“Segment” shall have the same meaning as described in Operating Agreement, Schedule 1, 
section 3.2.3(e), and the parallel provisions of Tariff, Attachment K-Appendix, section 3.2.3(e). 
 
Self-Supply: 
 
“Self-Supply” shall mean Capacity Resources secured by a Load-Serving Entity, by ownership 
or contract, outside a Reliability Pricing Model Auction, and used to meet obligations under this 
Attachment or the Reliability Assurance Agreement through submission in a Base Residual 
Auction or an Incremental Auction of a Sell Offer indicating such Market Seller’s intent that 
such Capacity Resource be Self-Supply.  Self-Supply may be either committed regardless of 
clearing price or submitted as a Sell Offer with a price bid. A Load Serving Entity's Sell Offer 
with a price bid for an owned or contracted Capacity Resource shall not be deemed “Self-
Supply,” unless it is designated as Self-Supply and used by the LSE to meet obligations under 
this Attachment or the Reliability Assurance Agreement. 
 
Self-Supply Entity: 
 
“Self-Supply Entity” shall mean the following types of Load Serving Entity that operate under 
long-standing business models: single customer entity, public power entity, or vertically 
integrated utility, where “vertically integrated utility” means a utility that owns generation, 
includes such generation in its regulated rates, and earns a regulated return on its investment in 
such generation or receives any cost recovery for such generation through bilateral contracts; 
“single customer entity”  means a Load Serving Entity that serves at retail only customers that 
are under common control with such Load Serving Entity, where such control means holding 
51% or more of the voting securities or voting interests of the Load Serving Entity and all its 
retail customers; and “public power entity” means cooperative and municipal utilities, including 
public power supply entities comprised of either or both of the same and rural electric 
cooperatives, and joint action agencies. 
 
Self-Supply Seller:

“Self-Supply Seller” shall mean, for purposes of evaluating Buyer-Side Market Power, the 
following types of Load Serving Entities that operate under long-standing business models: 
vertically integrated utility or public power entity, where “vertically integrated utility” means a 
utility that owns generation, includes such generation in its state-regulated rates, and earns a 
state-regulated return on its investment in such generation; and “public power entity” means 
electric cooperatives that are either rate regulated by the state or have their long-term resource 
plan approved or otherwise reviewed and accepted by a Relevant Electric Retail Regulatory 
Authority and municipal utilities or joint action agencies that are subject to direct regulation by a 
Relevant Electric Retail Regulatory Authority. 
 
Sell Offer: 
 
“Sell Offer” shall mean an offer to sell Capacity Resources in a Base Residual Auction, 
Incremental Auction, or Reliability Backstop Auction. 
 
Service Agreement: 
 
“Service Agreement” shall mean the initial agreement and any amendments or supplements 
thereto entered into by the Transmission Customer and the Transmission Provider for service 
under the Tariff. 
 
Service Commencement Date: 
 
“Service Commencement Date” shall mean the date the Transmission Provider begins to provide 
service pursuant to the terms of an executed Service Agreement, or the date the Transmission 
Provider begins to provide service in accordance with Tariff, Part II, section 15.3 or Tariff, Part 
III, section 29.1. 
 
Short-Term Firm Point-To-Point Transmission Service: 
 
“Short-Term Firm Point-To-Point Transmission Service” shall mean Firm Point-To-Point 
Transmission Service under Tariff, Part II with a term of less than one year. 
 
Short-term Project: 
 
“Short-term Project” shall have the same meaning provided in the Operating Agreement. 
 
Site: 
 
“Site” shall mean all of the real property, including but not limited to any leased real property 
and easements, on which the Customer Facility is situated and/or on which the Customer 
Interconnection Facilities are to be located. 
 
Small Commercial Customer:

“Small Commercial Customer,” as used in RAA, Schedule 6 and Tariff, Attachment DD-1, shall 
mean a commercial retail electric end-use customer of an electric distribution company that 
participates in a mass market demand response program under the jurisdiction of a RERRA and 
satisfies the definition of a “small commercial customer” under the terms of the applicable 
RERRA’s program, provided that the customer has an annual peak demand no greater than 
100kW. 
 
Small Generation Resource: 
 
“Small Generation Resource” shall mean an Interconnection Customer’s device of 20 MW or 
less for the production and/or storage for later injection of electricity identified in an 
Interconnection Request, but shall not include the Interconnection Customer’s Interconnection 
Facilities.  This term shall include Energy Storage Resources and/or other devices for storage for 
later injection of energy. 
 
Small Inverter Facility: 
 
“Small Inverter Facility” shall mean an Energy Resource that is a certified small inverter-based 
facility no larger than 10 kW. 
 
Small Inverter ISA: 
 
“Small Inverter ISA” shall mean an agreement among Transmission Provider, Interconnection 
Customer, and Interconnected Transmission Owner regarding interconnection of a Small Inverter 
Facility under Tariff, Part IV, section 112B. 
 
Special Member: 
 
 “Special Member” shall mean an entity that satisfies the requirements of Operating Agreement, 
Schedule 1, section 1.5A.02, and the parallel provisions of Tariff, Attachment K-Appendix, 
section 1.5A.02, or the special membership provisions established under the Emergency Load 
Response and Pre-Emergency Load Response Programs. 
 
Spot Market Backup: 
 
“Spot Market Backup” shall mean the purchase of energy from, or the delivery of energy to, the 
PJM Interchange Energy Market in quantities sufficient to complete the delivery or receipt 
obligations of a bilateral contract that has been curtailed or interrupted for any reason. 
 
Spot Market Energy: 
 
“Spot Market Energy” shall mean energy bought or sold by Market Participants through the PJM 
Interchange Energy Market at System Energy Prices determined as specified in Operating 
Agreement, Schedule 1, section 2, and the parallel provisions of Tariff, Attachment K-Appendix, 
section 2.

Start Additional Labor Costs: 
 
“Start Additional Labor Costs” shall mean additional labor costs for startup required above 
normal station manning levels.  
 
Start Fuel: 
 
For units without a soak process, “Start Fuel” shall consist of fuel consumed from first fire of the 
start process to first breaker closing, plus any fuel expended from last breaker opening to 
shutdown. 
 
For units with a soak process, “Start Fuel” is fuel consumed from first fire of the start process 
(initial reactor criticality for nuclear units) to dispatchable output (including auxiliary boiler 
fuel), plus any fuel expended from last breaker opening to shutdown, excluding normal plant 
heating/auxiliary equipment fuel requirements.  Start Fuel included for each temperature state 
from breaker closure to dispatchable output shall not exceed the unit specific soak time period 
reviewed and approved as part of the unit-specific parameter process detailed in Tariff, 
Attachment K-Appendix, section 6.6(c) or the defaults below: 
• Cold Soak Time = 0.73 * unit specific Minimum Run Time (in hours) 
• Intermediate Soak Time = 0.61 * unit specific Minimum Run Time (in hours) 
• Hot Soak Time = 0.43 * unit specific Minimum Run Time (in hours)   
 
Start-Up Costs: 
 
“Start-Up Costs” shall consist primarily of the cost of fuel, as determined by the unit’s start heat 
input (adjusted by the performance factor) times the fuel cost.  It also includes operating costs, 
Maintenance Adders, emissions allowances/adders, and station service cost.  Start-Up Costs can 
vary with the unit offline time being categorized in three unit temperature conditions: hot, 
intermediate and cold. 
 
For units with a steam turbine and a soak process (nuclear, steam, and combined cycle), “Start 
Fuel” is fuel consumed from first fire of start process (initial reactor criticality for nuclear units): 
Start-Up Costs shall mean the net unit costs from PJM’s notification to the level at which the unit 
can follow PJM’s dispatch, and from last breaker open to shutdown. 
 
For units without a steam turbine and no soak process (engines, combustion turbines, 
Intermittent Resources, and Energy Storage Resources): Start-Up Costs shall mean the unit costs 
from PJM’s notification to first breaker close and from last breaker open to shutdown.   
 
State: 
 
“State” shall mean the District of Columbia and any State or Commonwealth of the United 
States. 
 
State Commission:

“State Commission” shall mean any state regulatory agency having jurisdiction over retail 
electricity sales in any State in the PJM Region. 
 
State Estimator: 
 
“State Estimator” shall mean the computer model of power flows specified in Operating 
Agreement, Schedule 1, section 1.11A and the parallel provisions of Tariff, Attachment K-
Appendix, section 1.11A. 
 
State of Charge: 
 
“State of Charge” shall mean the operating parameter that represents the quantity of physical 
energy stored (measured in units of megawatt-hours) in an Energy Storage Resource Model 
Participant or in a storage component of a Hybrid Resource in proportion to its maximum State 
of Charge capability. State of Charge is quantified as defined in the PJM Manuals. 
 
State of Charge Management: 
 
“State of Charge Management” shall mean the control of State of Charge of an Energy Storage 
Resource Market Participant or a storage component of a Hybrid Resource using Charge and 
Discharge Economic Minimum and Maximum Megawatts (and, as applicable, charge) limits, 
changes in operating mode (as applicable), discharging (and, as applicable, charging) offer 
curves, and self-scheduling of non-dispatchable sales (and, as applicable, purchases) of energy in 
the PJM markets.  State of Charge Management shall not interfere with the obligation of a 
Market Seller of an Energy Storage Resource Model Participant or of a Hybrid Resource to 
follow PJM dispatch, consistent with all other resources. 
 
State Subsidy: 
 
“State Subsidy” shall mean a direct or indirect payment, concession, rebate, subsidy, non-
bypassable consumer charge, or other financial benefit that is as a result of any action, mandated 
process, or sponsored process of a state government, a political subdivision or agency of a state, 
or an electric cooperative formed pursuant to state law, and that  
(1) is derived from or connected to the procurement of (a) electricity or electric 
generation capacity sold at wholesale in interstate commerce, or (b) an attribute of the 
generation process for electricity or electric generation capacity sold at wholesale in 
interstate commerce; or 
(2) will support the construction, development, or operation of a new or existing Capacity 
Resource; or  
(3) could have the effect of allowing the unit to clear in any PJM capacity auction.  
Notwithstanding the foregoing, State Subsidy shall not include (a) payments, concessions, 
rebates, subsidies, or incentives designed to incent, or participation in a program, contract or 
other arrangement that utilizes criteria designed to incent or promote, general industrial 
development in an area or designed to incent siting facilities in that county or locality rather than 
another county or locality; (b) state action that imposes a tax or assesses a charge utilizing the 
parameters of a regional program on a given set of resources notwithstanding the tax or cost

having indirect benefits on resources not subject to the tax or cost (e.g., Regional Greenhouse 
Gas Initiative); (c) any indirect benefits to a Capacity Resource as a result of any transmission 
project approved as part of the Regional Transmission Expansion Plan; (d) any contract, legally 
enforceable obligation, or rate pursuant to the Public Utility Regulatory Policies Act or any other 
state-administered federal regulatory program (e.g., the Cross-State Air Pollution Rule); (e) any 
revenues from the sale or allocation, either direct or indirect, to an Entity Providing Supply 
Services to Default Retail Service Provider where such entity’s obligations was awarded through 
a state default procurement auction that was subject to independent oversight by a consultant or 
manager who certifies that the auction was conducted through a non-discriminatory and 
competitive bidding process, subject to the below condition, and provided further that nothing 
herein would exempt a Capacity Resource that would otherwise be subject to the minimum offer 
price rule pursuant to this Tariff; (f) any revenues for providing capacity as part of an FRR 
Capacity Plan or through bilateral transactions with FRR Entities; or (g) any voluntary and arm’s 
length bilateral transaction (including but not limited to those reported pursuant to Tariff, 
Attachment DD, section 4.6), such as a power purchase agreement or other similar contract 
where the buyer is a Self-Supply Entity and the transaction is (1) a short term transaction (one-
year or less) or (2) a long-term transaction that is the result of a competitive process that was not 
fuel-specific and is not used for the purpose of supporting uneconomic construction, 
development, or operation of the subject Capacity Resource, provided however that if the Self-
Supply Entity is responsible for offering the Capacity Resource into an RPM Auction, the 
specified amount of installed capacity purchased by such Self-Supply Entity shall be considered 
to receive a State Subsidy in the same manner, under the same conditions, and to the same extent 
as any other Capacity Resource of a Self-Supply Entity.  For purposes of subsection (e) of this 
definition, a state default procurement auction that has been certified to be a result of a non-
discriminatory and competitive bidding process shall: 
(i) 
have no conditions based on the ownership (except supplier diversity 
requirements or limits), location (except to meet PJM deliverability 
requirements), affiliation, fuel type, technology, or emissions of any resources or 
supply (except state-mandated renewable portfolio standards for which Capacity 
Resources are separately subject to the minimum offer price rule or eligible for an 
exemption); 
(ii) 
result in contracts between an Entity Providing Supply Services to Default Retail 
Service Provider and the electric distribution company for a retail default 
generation supply product and none of those contracts require that the retail 
obligation be sourced from any specific Capacity Resource or resource type as set 
forth in subsection (i) above; and 
(iii) 
establish market-based compensation for a retail default generation supply 
product that retail customers can avoid paying for by obtaining supply from a 
competitive retail supplier of their choice. 
 
 
Station Power: 
 
“Station Power” shall mean energy used for operating the electric equipment on the site of a 
generation facility located in the PJM Region or for the heating, lighting, air-conditioning and 
office equipment needs of buildings on the site of such a generation facility that are used in the

operation, maintenance, or repair of the facility.  Station Power does not include any energy (i) 
used to power synchronous condensers; (ii) used for pumping at a pumped storage facility; (iii) 
used in association with restoration or black start service; or (iv) that is Direct Charging Energy. 
 
Sub-meter: 
 
“Sub-meter” shall mean a metering point for electricity consumption that does not include all 
electricity consumption for the end-use customer as defined by the electric distribution company 
account number.  PJM shall only accept sub-meter load data from end-use customers for 
measurement and verification of Regulation service as set forth in the Economic Load Response 
rules and PJM Manuals. 
 
Summer-Period Capacity Performance Resource: 
 
“Summer-Period Capacity Performance Resource” shall have the same meaning specified in 
Tariff, Attachment DD, section 5.5A. 
 
Surplus Interconnection Customer: 
 
“Surplus Interconnection Customer” shall mean either an Interconnection Customer whose 
Generating Facility is already interconnected to the PJM Transmission System or one of its 
affiliates, or an unaffiliated entity that submits a Surplus Interconnection Request to utilize 
Surplus Interconnection Service within the Transmission System in the PJM Region.  A Surplus 
Interconnection Customer is not a New Service Customer.    
 
Surplus Interconnection Request: 
 
“Surplus Interconnection Request” shall mean a request submitted by a Surplus Interconnection 
Customer, pursuant to Tariff, Attachment RR, to utilize Surplus Interconnection Service within 
the Transmission System in the PJM Region.  A Surplus Interconnection Request is not a New 
Service Request. 
 
Surplus Interconnection Service: 
 
“Surplus Interconnection Service” shall mean any unneeded portion of Interconnection Service 
established in an Interconnection Service Agreement, such that if Surplus Interconnection 
Service is utilized, the total amount of Interconnection Service at the Point of Interconnection 
would remain the same. 
 
Switching and Tagging Rules: 
 
“Switching and Tagging Rules” shall mean the switching and tagging procedures of 
Interconnected Transmission Owners and Interconnection Customer as they may be amended 
from time to time.  
 
Synchronized Reserve:

“Synchronized Reserve” shall mean the reserve capability of generation resources that can be 
converted fully into energy or Economic Load Response Participant resources whose demand 
can be reduced within ten minutes from the request of the Office of the Interconnection 
dispatcher, and is provided by equipment that is electrically synchronized to the Transmission 
System. 
 
Synchronized Reserve Event: 
 
“Synchronized Reserve Event” shall mean a request from the Office of the Interconnection to 
generation resources and/or Economic Load Response Participant resources able, assigned or 
self-scheduled to provide Synchronized Reserve in one or more specified Reserve Zones or 
Reserve Sub-zones, within ten minutes, to increase the energy output or reduce load by a 
directed amount of the assigned or self-scheduled Synchronized Reserve. 
 
Synchronized Reserve Requirement: 
 
“Synchronized Reserve Requirement” shall mean the megawatts required to be maintained in a 
Reserve Zone or Reserve Sub-zone as Synchronized Reserve, absent any increase to account for 
additional reserves scheduled to address operational uncertainty.  The Synchronized Reserve 
Requirement is calculated in accordance with the PJM Manuals.  This requirement can only be 
satisfied by Synchronized Reserve resources. 
 
System Condition: 
 
“System Condition” shall mean a specified condition on the Transmission Provider’s system or 
on a neighboring system, such as a constrained transmission element or flowgate, that may 
trigger Curtailment of Long-Term Firm Point-to-Point Transmission Service using the 
curtailment priority pursuant to Tariff, Part II, section 13.6.  Such conditions must be identified 
in the Transmission Customer’s Service Agreement. 
 
System Energy Price: 
 
“System Energy Price” shall mean the energy component of the Locational Marginal Price, 
which is the price at which the Market Seller has offered to supply an additional increment of 
energy from a resource, calculated as specified in Operating Agreement, Schedule 1, section 2 
and the parallel provisions of Tariff, Attachment K-Appendix, section 2. 
 
System Impact Study: 
 
“System Impact Study” shall mean an assessment by the Transmission Provider of (i) the 
adequacy of the Transmission System to accommodate a Completed Application, an 
Interconnection Request or an Upgrade Request, (ii) whether any additional costs may be 
incurred in order to provide such transmission service or to accommodate an Interconnection 
Request, and (iii) with respect to an Interconnection Request, an estimated date that an 
Interconnection Customer’s Customer Facility can be interconnected with the Transmission

System and an estimate of the Interconnection Customer’s cost responsibility for the 
interconnection; and (iv) with respect to an Upgrade Request, the estimated cost of the requested 
system upgrades or expansion, or of the cost of the system upgrades or expansion, necessary to 
provide the requested incremental rights. 
 
System Protection Facilities: 
 
“System Protection Facilities” shall refer to the equipment required to protect (i) the 
Transmission System, other delivery systems and/or other generating systems connected to the 
Transmission System from faults or other electrical disturbance occurring at or on the Customer 
Facility, and (ii) the Customer Facility from faults or other electrical system disturbance 
occurring on the Transmission System or on other delivery systems and/or other generating 
systems to which the Transmission System is directly or indirectly connected.  System Protection 
Facilities shall include such protective and regulating devices as are identified in the Applicable 
Technical Requirements and Standards or that are required by Applicable Laws and Regulations 
or other Applicable Standards, or as are otherwise necessary to protect personnel and equipment 
and to minimize deleterious effects to the Transmission System arising from the Customer 
Facility.

5.5 
Eligibility for Participation in RPM Auctions 
 
(a) 
A Capacity Market Seller may submit a Sell Offer for a Capacity Resource in a Base 
Residual Auction or Incremental Auction only if such seller owns or has the contractual 
authority to control the output or load reduction capability of such resource and has not 
transferred such authority to another entity prior to submitting such Sell Offer. Capacity 
Resources must satisfy the capability and deliverability requirements of RAA, Schedule 9 and 
RAA, Schedule 10, the requirements for Demand Resources or Energy Efficiency Resources in 
Tariff, Attachment DD-1 and RAA, Schedule 6, as applicable, and, the criteria in Tariff, 
Attachment DD, section 5.5A. Effective with the 2025/2026 Delivery Year and subsequent 
Delivery Years, aA Planned Generation Capacity Resource may be included in a Sell Offer for 
an RPM Auction only if the Capacity Market Seller of such resource provides a binding notice 
of intent, as further detailed in the PJM Manuals, to submit a Sell Offer in such auction to the 
Office of the Interconnection no later than (a) the immediately preceding December 1 for a Base 
Residual Auction (except that for the 2025/2026 Delivery Year, such notice shall be submitted 
by December 12, 2023, and except that for the 2026/2027 and 2028/2029 Delivery Years, such 
notice shall be submitted by 180 days prior to the commencement of the offer period), or (b) 
ninety (90) days prior to the commencement of the offer period for an Incremental Auction.   
 
(b) 
Notwithstanding the foregoing, a committed RBP Resource shall be required to be 
offered into the relevant Base Residual Auction and is not required to submit a binding notice of 
intent to offer into such auction.  However, a committed RBP Resource that is not the subject of 
a notice of intent to be offered into the Base Residual Auction associated with the 2029/2030 
Delivery Year shall be offered into the Second Incremental Auction for the 2029/2030 Delivery 
Year. In the event a committed RBP Resource is not expected to be in-service or deliverable by 
the relevant Delivery Year, the Capacity Market Seller of such committed RBP Resource may 
notify the Office of the Interconnection, with supporting documentation, that the resource is not 
expected to be in-service or deliverable by the relevant Delivery Year. Such notice for a 
committed RBP Resource shall be submitted no later than (i) the immediately preceding 
December 1 for a Base Residual Auction or (ii) ninety (90) days prior to the commencement of 
the offer period for an Incremental Auction. A committed RBP Resource that provides such 
notice will be assessed any applicable RBP shortfall charge and not be allowed to be offered into 
the applicable RPM Auction.

5.5A Capacity Resource Types 
 
(a) 
Capacity Performance Resources 
 
Capacity Performance Resources are Capacity Resources which, to the extent such resources 
cleared in a Reliability Pricing Model Auction or are otherwise committed as a Capacity 
Resource, are obligated to deliver energy during the relevant Delivery Year as scheduled and/or 
dispatched by the Office of Interconnection during the Performance Assessment Intervals.  As 
further detailed in Tariff, Attachment DD, section 10A, Capacity Performance Resources that 
fail to meet this obligation will be subject to a Non-Performance Charge, unless excused 
pursuant to Tariff, Attachment DD, section 10A(d).  As further detailed in Tariff, Attachment 
DD, section 10B, Demand Resources that fail to meet this obligation during Non-PAI Events 
will be subject to a Non-Curtailment Charge.  Subject to 5.5A(a)(i), the following types of 
Capacity Resources are eligible to submit a Sell Offer as a Capacity Performance Resource: 
internal or external Generation Capacity Resources; Annual Demand Resources; Capacity 
Storage Resources; Annual Energy Efficiency Resources; and Qualifying Transmission 
Upgrades.  To the extent the underlying Capacity Resource is an external Generation Capacity 
Resource, such resource must meet, to the extent subsection (b) or (c) of this section is applicable 
to offers from such resource, meet the applicable requirements of such subsection, and if neither 
subsection (b) or (c) is applicable, then offers from such resource must the criteria for obtaining 
an exception to the Capacity Import Limit as contained in RAA, Article 1.  However, Electrical 
Distance requirements shall not apply to an external Generation Capacity Resource to the extent 
that such resource is an RBP Resource committed through the Reliability Backstop Procurement 
that is subsequently pseudo-tied to the PJM Region to the extent the Office of the 
Interconnection has elected to retain the resource, for the remainder of its RBP commitment 
term, within the PJM Region after the relevant Transmission Owner has exited PJM 
Interconnection, L.L.C. pursuant to Tariff, Attachment DD, section 18.7(a). 
 
(i) 
Process for Support and Review of Capacity Performance Resource Offers    
 
A. 
The Capacity Market Seller shall provide to the Office of the 
Interconnection and the Market Monitoring Unit, upon their request, all supporting data 
and information requested by either the Office of the Interconnection or the Market 
Monitoring Unit to evaluate whether the underlying Capacity Resource can meet the 
operational and performance requirements of Capacity Performance Resources.  The 
Capacity Market Seller shall have an ongoing obligation through the closing of the offer 
period for the RPM Auction to update the request to reflect any material changes. 
 
B. 
The Office of the Interconnection and the Market Monitoring Unit shall 
review any requested supporting data and information, and the Office of the 
Interconnection, considering advice and recommendation from the Market Monitoring 
Unit, shall reject a request for a resource to offer as a Capacity Performance Resource if 
the Capacity Market Seller does not demonstrate that it can reasonably be expected to 
meet its Capacity Performance obligations consistent with the resource’s offer by the 
relevant Delivery Year.  The Office of Interconnection shall provide its determination to 
reject eligibility of the resource as a Capacity Performance Resource, and notify the

Market Monitoring Unit, by no later than sixty-five (65) days prior to the date on which 
the offer period for the applicable RPM Auction commences.  A Capacity Market Seller 
that is dissatisfied with any determination hereunder may seek any remedies available to 
it from FERC; provided, however, that the Office of the Interconnection will proceed 
with administration of the Tariff and market rules unless and until ordered to do 
otherwise by FERC.  
 
(b) 
Offers from External Generation Capacity Resources for the 2020/2021 Delivery Year 
and Subsequent Delivery Years—General Rule 
 
For the 2020/2021 Delivery Year and any subsequent Delivery Year and for Capacity 
Performance Resource Sell Offers in any RPM Auction conducted for the 2018/2019 Delivery 
Year or 2019/2020 Delivery Year after May 9, 2017, unless excepted pursuant to subsection (c) 
below, a Capacity Market Seller may submit a Sell Offer for an external Generation Capacity 
Resource in an RPM Auction if the Capacity Market Seller demonstrates to PJM, by no later 
than five (5) business days prior to the commencement of the offer period for the relevant RPM 
Auction, that such resource meets all of the following requirements: 
(i)  
The Capacity Market Seller has obtained a determination that the Pseudo-Tie 
required for its external Generation Capacity Resource is feasible, including (without limitation) 
that such Pseudo-Tie meets the following requirements: 
 
(A) the external Generation Capacity Resource must have a minimum Electrical 
Distance impedance equal to or less than 0.065 p.u.; or is within one station of a 
transmission bus that has a minimum Electrical Distance impedance equal to or less than 
0.065 p.u.  With regard to this Electrical Distance requirement, the Office of the 
Interconnection shall:  
 
(1) post on its website the material assumptions, applicable to all tested 
generators, implemented in the modeling software used to conduct the 
Electrical Distance analysis (e.g., the general process used to define 
the facilities included in the Electrical Distance requirement and 
analysis for each Pseudo-Tie applicant);  
 
(2) upon  request by an applicant for a Pseudo-Tie, provide that applicant 
a copy of the results of the Electrical Distance analysis conducted by 
the Office of the Interconnection for the specific Pseudo-Tie requested 
by the applicant, as well as related work papers; and 
 
 (3) upon request by an applicant for a Pseudo-Tie, meet with that 
applicant to discuss specific modeling assumptions and the results of 
the Electrical Distance analysis for the specific Pseudo-Tie requested 
by that applicant; 
 
 
(B) at least one generation resource that has a historic economic minimum offer 
lower than its historic economic maximum offer, located inside the metered boundaries

of the PJM Region, has a minimum flow distribution impact of 1.5 percent on each 
eligible coordinated flowgate resulting from such Pseudo-Tie.  With regard to this 
requirement, the Office of the Interconnection shall:  
 
(1) post on its website the material assumptions, applicable to all tested 
generators, that have been implemented in the modeling software used 
to conduct the analysis to determine whether the requirement has been 
met (e.g., the definitions of the sink and source used in the market-to-
market analysis and the definition of eligible coordinated flowgates as 
applicable to the requirement);  
 
(2) upon request by an applicant for a Pseudo-Tie, provide that applicant a 
copy of the results of the market-to-market flowgate analysis conducted by 
the Office of the Interconnection for the specific Pseudo-Tie requested by 
the applicant, as well as related work papers;  and 
 
(3) upon request by an applicant for a Pseudo-Tie, meet with that applicant 
to discuss specific modeling assumptions and the results of the market-to-
market flowgate analysis conducted for the specific Pseudo-Tie requested 
by that applicant;  
 
 
(C) each external  entity with which PJM may be required to coordinate flowgates 
under an agreed congestion management process maintains a network model that 
produces results for such flowgates that are within two percent of the results produced by 
the PJM network model for such flowgates;   
 
(D) the Capacity Market Seller has secured written acknowledgement from the 
external Balancing Authority Areas that such Pseudo-Tie does not require tagging and 
that firm allocations associated with any coordinated flowgates applicable to the external 
Generation Capacity Resource under any agreed congestion management process then in 
effect between PJM and such Balancing Authority Area will be allocated to PJM.  
 
and the Capacity Market Seller has committed in writing that it will take all steps necessary to 
implement such Pseudo-Tie prior to the start of the relevant Delivery Year; 
 
(ii)  
it has, for transmission outside PJM, obtained long-term firm point-to-point 
transmission service (evaluated for deliverability from the unit-specific physical location of the 
resource to PJM load pursuant to a study that is reviewed and approved by PJM in accordance 
with PJM deliverability criteria to ensure uniformity for internal and external resource 
deliverability requirements), with rollover rights for the term of the transmission service that is 
confirmed by the Balancing Authority for the Balancing Authority Area where such resource is 
geographically located; and, as to transmission within PJM, has obtained Network External 
Designated Transmission Service; and 
 
(iii) 
it is, by written commitment of the Capacity Market Seller, subject to the same

obligations imposed on Generation Capacity Resources located in the PJM Region by Tariff, 
Attachment DD, section 6.6 to offer their capacity into RPM Auctions. 
 
A Capacity Market Seller that satisfies the above requirements with respect to an external 
Generation Capacity Resource Sell Offer submitted in an RPM Auction for a Delivery Year shall 
be required to demonstrate satisfaction of such requirements for any Sell Offer with respect to 
such resource submitted in an RPM Auction for any subsequent Delivery Year, including, 
without limitation, demonstration that the required external transmission service continues to 
satisfy PJM’s deliverability standards. 
 
 
 
(c) 
Offers from external Generation Capacity Resources for the 2020/2021 Delivery Year 
and Subsequent Delivery Years—Exception. 
 
A Capacity Market Seller of a Prior CIL Exception External Resource may continue to submit 
Sell Offers for such resource for any RPM Auction for any Delivery Year up to and including the 
2021/2022 Delivery Year (or, solely for any such resource that is (1) owned by a Load Serving 
Entity and used to self-supply (under arrangements initiated before June 1, 2016, with a duration 
of at least ten years) such entity’s PJM Region load or (2) the subject of a contract for energy or 
capacity or equivalent written agreement entered into on or before June 1, 2016 for a term of ten 
years or longer with a purchaser that is an internal PJM load customer, for any Delivery Year 
during the life of such resource for subparagraph (1) or for the term of the agreement under 
subparagraph (2)) so long as it continues to comply with all conditions on the grant of its 
exception to the Capacity Import Limit, subject to the following additional conditions:  
 
(i) 
for any Delivery Year, beginning with the 2017/2018 Delivery Year, for 
which such Prior CIL Exception External Resource has cleared an RPM Auction, PJM 
may in its sole judgment determine that the resource is not Operationally Deliverable for 
such Delivery Year because it does not satisfy the requirements of subsection (b).  If PJM 
determines a Prior CIL Exception External Resource is not Operationally Deliverable for 
a Delivery Year, it must notify the Capacity Market Seller of its determination by no later 
than October 1 immediately preceding such Delivery Year.  After receiving such notice, 
the Capacity Market Seller may elect to: 
 
 (A) take the necessary actions to make the Prior CIL Exception External 
Resource Operationally Deliverable, in PJM’s sole judgment, prior to the 
beginning of such Delivery Year, provided that PJM will, if transmission 
upgrades are required to make such resource Operationally Deliverable, facilitate 
the performance of transmission studies and otherwise cooperate with the external  
Transmission Provider of the system on which such upgrades are required to 
identify the upgrades required to meet PJM’s deliverability standards;  
 
(B) be relieved of its capacity obligation for such Delivery Year by 
providing written notice of such election to the Office of the Interconnection no 
later than seven (7) days prior to the posting of planning parameters for the Third

Incremental Auction for such Delivery Year as PJM will procure the replacement 
capacity in the Third Incremental Auction in accordance with Tariff, Attachment 
DD, sections 5.12(b)(ii) and 5.12(b)(iii), with no entitlement to any capacity 
revenues based on such resource, with no requirement to seek replacement for 
such capacity for such Delivery Year, with no penalty for non-performance or 
lack of commitment for such Delivery Year, and with no further must-offer 
obligation that would otherwise arise solely from clearing such capacity for such 
Delivery Year; or 
 
(C) procure, by purchase or otherwise, replacement in a sufficient quantity 
to replace the capacity that would have been provided by the Prior CIL Exception 
External Resource but for PJM’s determination that such resource is not 
Operationally Deliverable.  
 
(ii) 
Such Capacity Market Seller’s continued ability to offer such resource 
under this exception is conditioned on external Transmission Providers continuing to 
honor the firm status of the Capacity Market Seller’s transmission service for all Delivery 
Years for which such seller offers such resource under the exceptions provided in this 
subsection (c). 
 
(iii) 
A Capacity Market Seller offering and clearing a Prior CIL Exception 
External Resource pursuant to this subsection (c) shall be relieved of its must-offer 
obligation that would otherwise arise solely from clearing such capacity.  Such relief of 
the must-offer obligation shall be for any Delivery Year after the last Delivery Year for 
which it is permitted to offer such resource under this subsection (c). 
 
(iv)  
PJM will determine key triggers for when a Prior CIL Exception External 
Resource will not be Operationally Deliverable, including the need for: (1) a remedial 
action scheme or manual generation dump protocol to manage external transmission 
emergencies; (2) transmission facility switching arrangements that would have the effect 
of radializing load in order to manage external transmission emergencies; and (3) “out of 
market” external Balancing Authority or Transmission Operator directed dispatch 
instructions to manage excessive or unacceptable frequency of external regional 
reliability limit violations or (outside an interregional agreed congestion management 
process) of local reliability limit violations. 
 
(d) 
Seasonal Capacity Performance Resource 
A Seasonal Capacity Performance Resource shall mean a Summer-Period Capacity Performance 
Resource or Winter-Period Capacity Performance Resource, as defined below.  
 
i) 
Summer-Period Capacity Performance Resource 
The following types of Capacity Resources are eligible to submit a Sell Offer as a 
Summer-Period Capacity Performance Resource: Summer Period Demand Resource that 
has an average expected energy output during summer peak-hour periods consistently 
and measurably greater than its average expected energy output during winter peakhour

periods.  To the extent such resource clears an RPM Auction or is otherwise committed 
as a Summer-Period Capacity Performance Resource, it is obligated to reduce when 
dispatched by the Office of Interconnection during Performance Assessment Intervals or 
Non-PAI Event intervals occurring in the calendar months of June through October and 
the following May of the Delivery Year, and must satisfy the requirements of a Capacity 
Performance Resource for such period of time. As further detailed in Tariff, Attachment 
DD, sections 10A or 10B, Summer-Period Capacity Performance Resources that fail to 
meet this obligation will be subject to a Non-Performance Charge, unless excused 
pursuant to Tariff, Attachment DD, section 10A(d) and a Non-Curtailment Charge.   
 
ii) 
Winter-Period Capacity Performance Resource 
 
The following types of Capacity Resources are eligible to submit a Sell Offer as a 
Winter-Period Capacity Performance Resource: Intermittent Resource that has been 
granted additional Capacity Interconnection Rights related to the winter-period.  To the 
extent such resource clears an RPM Auction or is otherwise committed as a Winter-
Period Capacity Performance Resource, it is obligated to deliver energy as scheduled 
and/or dispatched by the Office of Interconnection during Performance Assessment 
Intervals occurring in the calendar months of November through April of the Delivery 
Year, and must satisfy the requirements of a Capacity Performance Resource for such 
period of time.  As further detailed in Tariff, Attachment DD, section 10A, Winter-Period 
Capacity Performance Resources that fail to meet this obligation will be subject to a Non-
Performance Charge, unless excused pursuant to Tariff, Attachment DD, section 10A(d).

5.14 
Clearing Prices and Charges 
 
 
a) 
Capacity Resource Clearing Prices  
 
For each Base Residual Auction and Incremental Auction, the Office of the Interconnection shall 
calculate a clearing price to be paid for each megawatt-day of Unforced Capacity that clears in 
such auction.  The Capacity Resource Clearing Price for each LDA will be the marginal value of 
system capacity for the PJM Region, without considering locational constraints, adjusted as 
necessary by any applicable Locational Price Adders, all as determined by the Office of the 
Interconnection based on the optimization algorithm.   If a Capacity Resource is located in more 
than one Locational Deliverability Area, it shall be paid the highest Locational Price Adder in 
any applicable LDA in which the Sell Offer for such Capacity Resource cleared.  
 
The Locational Price Adder applicable to each cleared Seasonal Capacity Performance Resource 
is determined during the post-processing of the RPM Auction results consistent with the manner 
in which the auction clearing algorithm recognizes the contribution of Seasonal Capacity 
Performance Resource Sell Offers in satisfying an LDA’s reliability requirement.  For each LDA 
with a positive Locational Price Adder with respect to the immediate higher level LDA, starting 
with the lowest level constrained LDAs and moving up, PJM determines the quantity of equally 
matched Summer-Period Capacity Performance Resources and Winter-Period Capacity 
Performance Resources located and cleared within that LDA.  Up to this quantity, the cleared 
Summer-Period Capacity Performance Resources and Winter-Period Capacity Performance 
Resources with the lowest Sell Offer prices will be compensated using the highest Locational 
Price Adder applicable to such LDA; and any remaining Seasonal Capacity Performance 
Resources cleared within the LDA are effectively moved to the next higher level constrained 
LDA, where they are considered in a similar manner for compensation. 
 
 
b) 
Resource Make-Whole Payments 
 
If a Sell Offer specifies a minimum block, and only a portion of such block is needed to clear the 
market in a Base Residual or Incremental Auction, the MW portion of such Sell Offer needed to 
clear the market shall clear, and such Sell Offer shall set the marginal value of system capacity.  
In addition, the Capacity Market Seller shall receive a Resource Make-Whole Payment equal to 
the Capacity Resource Clearing Price in such auction times the difference between the Sell 
Offer's minimum block MW quantity and the Sell Offer's cleared MW quantity.  If the Sell Offer 
price of a cleared Seasonal Capacity Performance Resource exceeds the applicable Capacity 
Resource Clearing Price, the Capacity Market Seller shall receive a Resource Make-Whole 
Payment equal to the difference between the Sell Offer price and Capacity Resource Clearing 
Price in such RPM Auction.  The cost for any such Resource Make-Whole Payments required in 
a Base Residual Auction or Incremental Auction for adjustment of prior capacity commitments 
shall be collected pro rata from all LSEs in the LDA in which such payments were made, based 
on their Daily Unforced Capacity Obligations. The cost for any such Resource Make-Whole 
Payments required in an Incremental Auction for capacity replacement shall be collected from all 
Capacity Market Buyers in the LDA in which such payments were made, on a pro-rata basis 
based on the MWs purchased in such auction. 
 
 
c) 
New Entry Price Adjustment

A Capacity Market Seller that submits a Sell Offer based on a Planned Generation Capacity 
Resource that clears in the BRA for a Delivery Year may, at its election, submit Sell Offers with 
a New Entry Price Adjustment in the BRAs for the two immediately succeeding Delivery Years 
if: 
 
1. 
Such Capacity Market Seller provides notice of such election at the time it 
submits its Sell Offer for such resource in the BRA for the first Delivery Year for which such 
resource is eligible to be considered a Planned Generation Capacity Resource.  When the 
Capacity Market Seller provides notice of such election, it must specify whether its Sell Offer is 
contingent upon qualifying for the New Entry Price Adjustment.  The Office of the 
Interconnection shall not clear such contingent Sell Offer if it does not qualify for the New Entry 
Price Adjustment. 
 
2. 
All or any part of a Sell Offer from the Planned Generation Capacity 
Resource submitted in accordance with section 5.14(c)(1) is the marginal Sell Offer that sets the 
Capacity Resource Clearing Price for the LDA. 
 
3. 
Acceptance of all or any part of a Sell Offer that meets the conditions in 
section 5.14(c)(1)-(2) in the BRA increases the total Unforced Capacity committed in the BRA 
(including any minimum block quantity) for the LDA in which such Resource will be located 
from a megawatt quantity below the LDA Reliability Requirement to a megawatt quantity at or 
above a megawatt quantity at the price-quantity point on the VRR Curve at which the price is 
0.40 times the applicable Net CONE divided by (one minus the pool-wide average EFORd) 
through the 2024/2025 Delivery Year, and beginning with the 2025/2026 Delivery Year, divided 
by the applicable ELCC Class Rating for the Reference Resource. 
 
4. 
Such Capacity Market Seller submits Sell Offers in the BRA for the two 
immediately succeeding Delivery Years for the entire Unforced Capacity of such Generation 
Capacity Resource committed in the first BRA under section 5.14(c)(1)-(2) equal to the lesser of: 
A) the price in such seller’s Sell Offer for the BRA in which such resource qualified as a Planned 
Generation Capacity Resource that satisfies the conditions in section 5.14(c)(1)-(3); or B) 0.90 
times the Net CONE applicable in the first BRA in which such Planned Generation Capacity 
Resource meeting the conditions in section 5.14(c)(1)-(3) cleared, on an Unforced Capacity 
basis, for such LDA. 
 
5. 
If the Sell Offer is submitted consistent with section 5.14(c)(1)-(4) the 
foregoing conditions, then: 
 
(i) 
in the first Delivery Year, the Resource sets the Capacity Resource 
Clearing Price for the LDA and all cleared resources in the LDA receive 
the Capacity Resource Clearing Price set by the Sell Offer as the marginal 
offer, in accordance with Tariff, Attachment DD, section 5.12(a) and 
section 5.14(a) above.  
 
(ii) 
in either of the subsequent two BRAs, if any part of the Sell Offer from 
the Resource clears, it shall receive the Capacity Resource Clearing Price

for such LDA for its cleared capacity and for any additional minimum 
block quantity pursuant to section 5.14(b) above; or 
 
(iii) 
if the Resource does not clear, it shall be deemed resubmitted at the 
highest price per MW-day at which the megawatt quantity of Unforced 
Capacity of such Resource that cleared the first-year BRA will clear the 
subsequent-year BRA pursuant to the optimization algorithm described in 
Tariff, Attachment DD, section 5.12(a), and  
 
(iv) 
the resource with its Sell Offer submitted shall clear and shall be 
committed to the PJM Region in the amount cleared, plus any additional 
minimum-block quantity from its Sell Offer for such Delivery Year, but 
such additional amount shall be no greater than the portion of a minimum-
block quantity, if any, from its first-year Sell Offer satisfying section 
5.14(c)(1)-(3) above that is entitled to compensation pursuant to section 
5.14(b) above; and 
 
(v) 
the Capacity Resource Clearing Price, and the resources cleared, shall be 
re-determined to reflect the resubmitted Sell Offer.  In such case, the 
Resource for which the Sell Offer is submitted pursuant to section 
5.14(c)(1)-(4) above shall be paid for the entire committed quantity at the 
Sell Offer price that it initially submitted in such subsequent BRA.  The 
difference between such Sell Offer price and the Capacity Resource 
Clearing Price (as well as any difference between the cleared quantity and 
the committed quantity), will be treated as a Resource Make-Whole 
Payment in accordance with section 5.14(b) above.  Other capacity 
resources that clear the BRA in such LDA receive the Capacity Resource 
Clearing Price as determined in section 5.14(a) above. 
 
6. 
The failure to submit a Sell Offer consistent with section 5.14(c)(i)-(iii) 
above in the BRA for Delivery Year 3 shall not retroactively revoke the New Entry Price 
Adjustment for Delivery Year 2.  However, the failure to submit a Sell Offer consistent with 
section 5.14(c)(4) above in the BRA for Delivery Year 2 shall make the resource ineligible for 
the New Entry Pricing Adjustment for Delivery Years 2 and 3. 
 
7. 
For each Delivery Year that the foregoing conditions are satisfied, the 
Office of the Interconnection shall maintain and employ in the auction clearing for such LDA a 
separate VRR Curve, notwithstanding the outcome of the test referenced in Tariff, Attachment 
DD, section 5.10(a)(ii). 
 
8. 
On or before August 1, 2012, PJM shall file with FERC under FPA 
section 205, as determined necessary by PJM following a stakeholder process, tariff changes to 
establish a long-term auction process as a not unduly discriminatory means to provide adequate 
long-term revenue assurances to support new entry, as a supplement to or replacement of this 
New Entry Price Adjustment.    
 
 
d) 
Qualifying Transmission Upgrade Payments

A Capacity Market Seller that submitted a Sell Offer based on a Qualifying Transmission 
Upgrade that clears in the Base Residual Auction shall receive a payment equal to the Capacity 
Resource Clearing Price, including any Locational Price Adder, of the LDA into which the 
Qualifying Transmission Upgrade is to increase Capacity Emergency Transfer Limit, less the 
Capacity Resource Clearing Price, including any Locational Price Adder, of the LDA from 
which the upgrade was to provide such increased CETL, multiplied by the megawatt quantity of 
increased CETL cleared from such Sell Offer.  Such payments shall be reflected in the 
Locational Price Adder determined as part of the Final Zonal Capacity Price for the Zone 
associated with such LDAs, and shall be funded through a reduction in the Capacity Transfer 
Rights allocated to Load-Serving Entities under Tariff, Attachment DD, section 5.15, as set forth 
in that section.  PJMSettlement shall be the Counterparty to any cleared capacity transaction 
resulting from a Sell Offer based on a Qualifying Transmission Upgrade.   
 
 
e) 
Locational Reliability Charge  
 
In accordance with the Reliability Assurance Agreement, each LSE shall incur a Locational 
Reliability Charge (subject to certain offsets and other adjustments as described in and Tariff, 
Attachment DD, section 5.15) equal to such LSE’s Daily Unforced Capacity Obligation in a 
Zone during such Delivery Year multiplied by the applicable Final Zonal Capacity Price in such 
Zone.  PJMSettlement shall be the Counterparty to the LSEs’ obligations to pay, and payments 
of, Locational Reliability Charges. 
 
 
f) 
The Office of the Interconnection shall determine Zonal Capacity Prices in 
accordance with the following, based on the optimization algorithm: 
 
i) 
The Office of the Interconnection shall calculate and post the Preliminary 
Zonal Capacity Prices for each Delivery Year following the Base Residual Auction for such 
Delivery Year. The Preliminary Zonal Capacity Price for each Zone shall be the sum of: (1) the 
marginal value of system capacity for the PJM Region, without considering locational 
constraints; (2) the Locational Price Adder, if any, for the LDA in which such Zone is located; 
provided however, that if the Zone contains multiple LDAs with different Capacity Resource 
Clearing Prices, the Zonal Capacity Price shall be a weighted average of the Capacity Resource 
Clearing Prices for such LDAs, weighted by the Unforced Capacity of Capacity Resources 
cleared in each such LDA; (3) an adjustment, if required, to account for adders paid to Annual 
Resources in the LDA for which the zone is located; (4) an adjustment, if required, to account for 
Resource Make-Whole Payments; and (5) an adjustment, if required to provide sufficient 
revenue for payment of any PRD Credits, all as determined in accordance with the optimization 
algorithm. 
 
ii) 
The Office of the Interconnection shall calculate and post the Adjusted 
Zonal Capacity Price following each Incremental Auction.  The Adjusted Zonal Capacity Price 
for each Zone shall equal the sum of:  (1) the average marginal value of system capacity 
weighted by the Unforced Capacity cleared in all auctions previously conducted for such 
Delivery Year (excluding any Unforced Capacity cleared as replacement capacity); (2) the 
average Locational Price Adder weighted by the Unforced Capacity cleared in all auctions 
previously conducted for such Delivery Year (excluding any Unforced Capacity cleared as

replacement capacity); (3) an adjustment, if required, to account for adders paid to Annual 
Resources for all auctions previously conducted for such Delivery Year (excluding any Unforced 
Capacity cleared as replacement capacity); (4) an adjustment, if required, to account for 
Resource Make-Whole Payments for all actions previously conducted (excluding any Resource 
Make-Whole Payments to be charged to the buyers of replacement capacity); and (5) an 
adjustment, if required to provide sufficient revenue for payment of any PRD Credits; and (6) an 
adjustment, if required, to reflect any changes in final Accredited UCAP for resources that are 
counted as capacity in accordance with Tariff, Attachment DD, section 5.3(b). The Adjusted 
Zonal Capacity Price may decrease if Unforced Capacity is decommitted or the Resource 
Clearing Price decreases in an Incremental Auction.  
 
iii) 
The Office of the Interconnection shall calculate and post the Final Zonal 
Capacity Price for each Delivery Year after the final auction is held for such Delivery Year, as 
set forth above.  The Final Zonal Capacity Price for each Zone shall equal the Adjusted Zonal 
Capacity Price, as further adjusted to reflect any decreases in the Nominated Demand Resource 
Value of any existing Demand Resource cleared in the Base Residual Auction, First Incremental, 
or Second Incremental Auction. 
 
 
g) 
Resource Substitution Charge 
 
Each Capacity Market Buyer in an Incremental Auction securing replacement 
capacity shall pay a Resource Substitution Charge equal to the Capacity Resource Clearing Price 
resulting from such auction multiplied by the megawatt quantity of Unforced Capacity purchased 
by such Market Buyer in such auction.  
 
 
h) 
[Reserved for future use] 
 
h-1) 
[Reserved for future use] 
h-2) 
Minimum Offer Price Rule Effective with the 2023/2024 Delivery Year 
 
(1) 
Certification Requirement.  
 
(A) 
Except for any RBP Resources committed through the Reliability 
Backstop Procurement, Bby no later than one hundred and fifty (150) days prior to the 
commencement of the offer period of any RPM Auction conducted for the 2024/2025 Delivery 
Year and all subsequent Delivery Years, and by the date posted on the PJM website for the 
2023/2024 Delivery Year, each Capacity Market Seller must certify to the Office of 
Interconnection for each Generation Capacity Resource and each applicable DER Capacity 
Aggregation Resource the Capacity Market Seller intends to offer into the RPM Auction, in 
accordance with the PJM Manuals:  
 
(i) whether or not the Generation Capacity Resource is receiving or 
expected to receive Conditioned State Support under any legislative or other governmental 
policy or program that has been enacted or effective at the time of the certification; and   
 
(ii) whether or not the Capacity Market Seller acknowledges and 
understands that the Exercise of Buyer-Side Market Power is not permitted in RPM Auctions,

and does not intend to submit a Sell Offer for their Generation Capacity Resource as an Exercise 
of Buyer-Side Market Power. 
 
(B) 
All Capacity Market Sellers shall be responsible for the accuracy 
of each certification and its conformance with the Tariff irrespective of any guidance developed 
by the Office of the Interconnection and the Market Monitoring Unit. 
 
(C) 
Once a Capacity Market Seller has certified whether or not a 
Generation Capacity Resource is receiving or expected to receive Conditioned State Support, the 
certification requirements in subsection (A)(i) above do not apply and the status of such 
Generation Capacity Resource will remain unchanged unless and until the Capacity Market 
Seller (or a subsequent Capacity Market Seller of the underlying resource) that owns or controls 
such Generation Capacity Resource provides a certification of a change in such status, the Office 
of the Interconnection removes such status, or by FERC order.  All Capacity Market Sellers shall 
have an ongoing obligation to certify to the Office of Interconnection and the Market Monitoring 
Unit a Generation Capacity Resource’s material change in status regarding whether such 
resource is receiving or expected to receive Conditioned State Support within 30 days of such 
material change. Nothing in this provision shall supersede the requirement for all Capacity 
Market Sellers to certify to the Office of Interconnection pursuant to Tariff, Attachment DD, 
section 5.14(h-2)(1)(A)(ii).  
 
(2) 
Determining Generation Capacity Resources Subject to the Minimum 
Offer Price Rule.   
 
(A) 
Conditioned State Support.   
 
(i) If the Office of the Interconnection reasonably believes a 
government policy or program would provide Conditioned State Support or a Capacity Market 
Seller certifies that it is receiving or is expected to receive Conditioned State Support associated 
with a given Generation Capacity Resource, the Office of Interconnection shall submit, pursuant 
to section 205 of the Federal Power Act, 16 U.S.C. § 824d, a filing at FERC indicating the Office 
of the Interconnection’s intent to classify the government policy or program from which that 
support is derived as Conditioned State Support (and adding such policy or program to the list in 
Tariff, Attachment DD-3) and apply the Minimum Offer Price Rule to each Generation Capacity 
Resource reasonably expected to receive such Conditioned State Support.  If FERC has already 
ruled on whether a specific government program or policy constitutes Conditioned State Support 
and such policy or program is listed in Tariff, Attachment DD-3, the Office of the 
Interconnection shall not be required to submit the filing described in the preceding sentence.   
 
(ii) Government policies or programs that do not provide payments 
or other financial benefit outside of PJM markets and do not provide payment or other financial 
benefit in exchange for the sale of a FERC-jurisdictional product conditioned on clearing in any 
RPM Auction do not constitute Conditioned State Support. Examples of such government 
policies that do not constitute Conditioned State Support may include, but are not limited to: 
policies designed to procure, incent, or require environmental attributes, whether bundled or 
unbundled (e.g., Renewable Energy Credits, Zero Emission Credits; Regional Greenhouse Gas 
Initiative); economic development programs and policies; tax incentives; state retail default

service auctions; policies or programs that provide incentives related to fuel supplies; any 
contract, legally enforceable obligation, or rate pursuant to the Public Utility Regulatory Policies 
Act or any other state-administered federal regulatory program (e.g., Cross-State Air Pollution 
Rule). In addition, Conditioned State Support shall not be determined solely based on the 
business model of the Capacity Market Seller, such that the fact that a Self-Supply Entity is the 
Capacity Market Seller, for example, is not a basis for determining Conditioned State Support.   
 
(iii) Upon FERC acceptance (whether by order or operation of law) 
that a government policy or program or contract with a state entity constitutes Conditioned State 
Support, a Generation Capacity Resource for which a Capacity Market Seller certifies pursuant 
to Tariff, Attachment DD, section 5.14(h-2)(1)(A)(i) that it is receiving Conditioned State 
Support or is reasonably expected to receive such Conditioned State Support, as identified by the 
Office of the Interconnection, with the advice and input of the Market Monitoring Unit, will be 
subject to the provisions of the Minimum Offer Price Rule. 
 
(B) 
Exercise of Buyer-Side Market Power  
 
(i) Except for a committed RBP Resource, Iif a Capacity Market 
Seller does not certify that it acknowledges the prohibition of the Exercise of Buyer Side Market 
Power and the Capacity Market Seller intends to exercise Buyer-Side Market Power for this 
Generation Capacity Resource, then the underlying Capacity Resource shall be subject to the 
MOPR pursuant to Tariff, Attachment DD, section 5.14(h-2)(1)(A)(i). If the Office of the 
Interconnection and/or the Market Monitoring Unit reasonably suspects that a certification 
submitted under Tariff, Attachment DD, section 5.14(h-2)(1)(A)(ii) contains fraudulent or 
material misrepresentations such that the Capacity Market Seller’s Generation Capacity 
Resource may be the subject of a Sell Offer that would be an Exercise of Buyer-Side Market 
Power or otherwise reasonably suspects that a Generation Capacity Resource may be the subject 
of a Sell Offer that would be an Exercise of Buyer-Side Market Power, the Office of the 
Interconnection and/or the Market Monitoring Unit shall initiate a fact-specific review into the 
facts and circumstances regarding the Generation Capacity Resource and whether the Capacity 
Market Seller has the ability and incentive to exercise Buyer-Side Market Power with respect to 
such Generation Capacity Resource.  During such fact-specific review, the Capacity Market 
Seller will have the opportunity to explain and justify why a Sell Offer for the Generation 
Capacity Resource would not be an Exercise of Buyer-Side Market Power.  The Office of the 
Interconnection and/or the Market Monitoring Unit shall notify the Capacity Market Seller of the 
bases for inquiry and initiation of review at least 135 days in advance of the RPM Auction 
conducted for the 2024/2025 Delivery Year and all subsequent Delivery Years, and by the date 
posted on the PJM website for the 2023/2024 Delivery Year.  
 
In initiating a review, the Office of the Interconnection and/or the 
Market Monitoring Unit shall provide the affected Capacity Market Seller, in writing, the basis 
for its inquiry, including, but not limited to, the Generation Capacity Resource(s), and the 
purported beneficiary of any price suppression.  The Office of the Interconnection and/or the 
Market Monitoring Unit may request from the Capacity Market Seller additional information and 
documentation that is reasonably related to the basis for its inquiry, provided that, the Office of 
the Interconnection and the Market Monitoring Unit shall confer with the Capacity Market Seller 
in advance of any such requests.  The Capacity Market Seller shall provide any additional

supporting information and documentation requested by the Office of the Interconnection and/or 
the Market Monitoring Unit, and any other information and documentation the Capacity Market 
Seller believes may justify the conduct or action in question as not representing an Exercise of 
Buyer-Side Market Power, within 15 days or other such timeline as agreed to in writing by the 
Office of the Interconnection, Market Monitoring Unit and Capacity Market Seller.   
 
The fact-specific review will determine, as necessary, whether a 
Capacity Market Seller has the ability and incentive to submit a Sell Offer for the Generation 
Capacity Resource that could be an Exercise of Buyer-Side Market Power, as follows: 
 
(a) To determine whether a Capacity Market Seller may 
have Buyer Side Market Power associated with the Generation Capacity Resource for the 
applicable RPM Auction, the Office of the Interconnection and/or the Market Monitoring Unit 
will perform ex-ante testing to determine the extent to which a shift in the supply curve by a 
number of megawatts equal to the size of the Generation Capacity Resource would affect RPM 
Auction clearing prices, where such analysis would reflect expected supply and demand 
conditions in the region of the market clearing prices and quantities in recent RPM Auctions, 
would reflect whether the relevant LDAs have been constrained in recent RPM Auctions, and 
would reflect reasonably expected material changes in an LDA including the modeling of the 
LDA and expected changes in supply and demand for the applicable Delivery Year.  To the 
extent the foregoing analyses show that the Generation Capacity Resource would have a material 
effect on RPM Auction clearing prices, the Capacity Market Seller shall be deemed to have the 
ability to exercise Buyer Side Market Power. 
 
(b) To determine whether the Capacity Market Seller’s 
submission of a Sell Offer at any given price level for such Generation Capacity Resource may 
constitute an Exercise of Buyer-Side Market Power, the Office of the Interconnection and/or the 
Market Monitoring Unit shall perform ex-ante testing to determine whether, given the ability to 
suppress prices identified in the relevant LDAs and the PJM Region, such price suppression 
would be economically beneficial to the Capacity Market Seller by comparing its expected cost 
with its economic benefit, and where the expected cost shall reflect the excess economic costs of 
the resource above expected market revenues, and the expected benefit shall reflect the expected 
cost savings to the expected net short position (based on estimated capacity obligations and 
owned and contracted capacity measured on a three-year average basis for the three years 
starting with the first day of the Delivery Year associated with the RPM Auction in which the 
Generation Capacity Resource is being offered) in the relevant LDAs and RTO multiplied by the 
price change resulting from offering the resource uneconomically. In this analysis, the Office of 
Interconnection and/or the Market Monitoring Unit shall consider whether any capacity 
obligations in which the capacity costs based on RPM Auction clearing prices are directly passed 
through to load and consider whether the price of any contracted capacity passes through RPM 
Auction clearing prices. If the expected benefit outweighs the expected cost, the Capacity Market 
Seller shall be deemed to have the incentive to exercise Buyer Side Market Power. If a resource 
offer can be justified, economically or otherwise, without consideration of the benefit to the 
Capacity Market Seller of the suppressed prices, the Capacity Market Seller shall be deemed not 
to have the incentive to exercise Buyer Side Market Power with respect to that resource. Out-of-
market compensation (such as from renewable energy credits and zero emission credits) that are 
not tied to either Conditioned State Support or a bilateral contract that directs the submission of

an offer to lower market clearing prices may be used to support the economics of the resource 
under review. 
 
(ii) The following nonexhaustive list of circumstances would 
preclude an inquiry into or determination regarding an Exercise of Buyer-Side Market Power in 
the course of a review initiated pursuant to subsection (i) above:  (a) the Generation Capacity 
Resource is a merchant generation supply resources that is not contracted to an entity with a 
Load Interest; (b)  the Generation Capacity Resource is acquired by or under the contractual 
control of the Capacity Market Seller through a competitive and non-discriminatory procurement 
process open to new and existing resources; or (c) the Generation Capacity Resource is owned 
by or bilaterally contracted to a Self-Supply Seller and such resource is demonstrated as 
consistent with or included in the Self-Supply Seller’s long-range resource plan (e.g., a long-
range hedging plan) that is approved or otherwise reviewed and accepted by the RERRA, 
provided that any such plan approval or contracts do not direct the submission of an uneconomic 
offer to deliberately lower market clearing prices or for the Capacity Market Seller to otherwise 
perform an Exercise of Buyer-Side Market Power. In addition, to the extent a Generation 
Capacity Resource may receive compensation in support of characteristics aligned with well-
demonstrated customer preferences, such compensation shall not, in and of itself, be a basis for 
the determination of Buyer-Side Market Power. 
 
(iii) Based on the foregoing tests and fact-specific review, 
including the facts and circumstances of the Generation Capacity Resource, the Office of the 
Interconnection, with the advice and input of the Market Monitoring Unit, shall determine 
whether a Generation Capacity Resource may be the subject of a Sell Offer that would be an 
Exercise of Buyer-Side Market Power.  If the Office of the Interconnection, with the advice and 
input of the Market Monitoring Unit, determines that a Generation Capacity Resource may be 
the subject of a Sell Offer that would be an Exercise of Buyer-Side Market Power or the 
Capacity Market Seller certifies that it intends to exercise Buyer-Side Market Power, then such 
resource will be subject to the provisions of the Minimum Offer Price Rule.  If the resource will 
be subject to the provisions of the Minimum Offer Price Rule, the Office of the Interconnection 
shall include in the notice a written explanation for such determination. A Capacity Market 
Seller that is dissatisfied with the Office of the Interconnection’s determination of whether a 
given Generation Capacity Resource is subject to the Minimum Offer Price Rule  may seek any 
remedies available to it from FERC; provided, however, that the Office of the Interconnection 
will proceed with administration of the Tariff and market rules based on its determination 
hereunder unless FERC by order directs otherwise. 
 
(C) 
Failure to timely submit a certification.  Any Generation Capacity 
Resource for which a Capacity Market Seller has not timely submitted the certifications required 
under Tariff, Attachment DD, section 5.14(h-2)(1) shall be subject to the provisions of the 
Minimum Offer Price Rule.  Notwithstanding the foregoing, if a Capacity Market Seller submits 
a timely unit-specific exception pursuant to Tariff, Attachment DD, section 5.14(h-2)(4) for the 
relevant Delivery Year, and PJM approves the unit-specific MOPR Floor Offer Price, then the 
Capacity Market Seller may use such floor price regardless of whether it timely submitted the 
foregoing certifications.

(3) 
Minimum Offer Price Rule.  Any Sell Offer for a Generation Capacity 
Resource that is subject to the provisions of the Minimum Offer Price Rule pursuant to Tariff, 
Attachment DD, section 5.14(h-2)(2) shall have an offer price no lower than the applicable 
MOPR Floor Offer Price, unless the applicable MOPR Floor Offer Price is higher than the 
applicable Market Seller Offer Cap, in which circumstance the Capacity Market Seller, to 
participate in an RPM Auction, must request a unit-specific value determined in accordance with 
the unit-specific MOPR Floor Offer Price process, and the unit-specific MOPR Floor Offer Price 
shall establish the offer level for such resource.   
 
(A) 
New Entry MOPR Floor Offer Price. For a Generation Capacity 
Resource that is subject to the provisions of the Minimum Offer Price Rule pursuant to Tariff, 
Attachment DD, section 5.14(h-2)(2) and for which a Sell Offer based on that resource, or any 
uprate of such   Generation Capacity Resource participating in the generation interconnection 
process under Tariff, Part IV, Subpart A, that has not cleared an RPM Auction for any Delivery 
Year,  the applicable MOPR Floor Offer Price, based on the net cost of new entry for the 
resource type, shall be, at the election of the Capacity Market Seller, (i) the unit-specific value 
determined in accordance with the unit-specific MOPR Floor Offer Price process in Tariff, 
Attachment DD, section 5.14(h-2)(4) below or (ii) if applicable, the default New Entry MOPR 
Floor Offer Price for the applicable resource based on the gross cost of new entry values shown 
in the table below, as adjusted for Delivery Years subsequent to the 2022/2023 or 2026/2027 
Delivery Year, as applicable, net of estimated net energy and ancillary service revenues for the 
resource type and Zone in which the resource is located.  
 
Resource Type 
Through the 2025/2026 
Delivery Years:  
Gross Cost of New Entry 
(2022/2023 $/ MW-day) 
(Nameplate) 
For the 2026/2027 Delivery 
Year and Subsequent Delivery 
Years:  
Gross Cost of New Entry 
(2026/2027 $/ MW-day) 
(Nameplate) 
Nuclear 
$2,000 
$2,568 
Coal 
$1,068 
$1,480 
Combined Cycle 
$320 
$540 
Combustion Turbine 
$294 
$394 
Fixed Solar PV 
$271 
$298 
Tracking Solar PV 
$290 
$321 
Onshore Wind 
$420 
$438 
Offshore Wind 
$1,155 
$1,351 
Battery Energy Storage 
$532 
$502 
 
The gross cost of new entry values in the table above are expressed in dollars per MW-day in 
terms of nameplate megawatts.  For purposes of submitting a Sell Offer, the gross cost of new 
entry values must be converted to a net cost of new entry by subtracting the estimated net energy 
and ancillary service revenues, as determined below, from the gross cost of new entry.  However, 
the resultant net cost of new entry of the battery energy storage resource type in the table above 
must be multiplied by 2.5.  The net cost of new entry based on nameplate capacity is then 
converted to Unforced Capacity (“UCAP”) MW-day.  For the 2023/2024 and 2024/2025

Delivery Years, the net cost of new entry is adjusted using: for battery storage, wind, and solar 
resource types, the applicable ELCC Class Rating; or for all other generation resource types, the 
applicable class average EFORd.  For the 2025/2026 Delivery Year and subsequent Delivery 
Years, the net cost of new entry is adjusted by the applicable class average Accredited UCAP 
Factor. The resulting default New Entry MOPR Floor Offer price in UCAP/MW-day terms shall 
be applied to each MW offered for the Capacity Resource regardless of the actual Sell Offer 
quantity and regardless of whether the Sell Offer is for a Seasonal Capacity Performance 
Resource. 
  
Commencing with the Base Residual Auction for the 2023/2024 Delivery Year, the Office of the 
Interconnection shall adjust the default gross costs of new entry in the table above and post the 
preliminary estimates of the adjusted applicable default New Entry MOPR Floor Offer Prices on 
its website, by no later than one hundred fifty (150) days prior to the commencement of the offer 
period for each Base Residual Auction.  To determine the adjusted applicable default New Entry 
MOPR Floor Offer Prices for all resource types, the Office of the Interconnection shall adjust the 
gross costs of new entry utilizing, for combustion turbine and combined cycle resource types, the 
same Applicable BLS Composite Index applied for such Delivery Year to adjust the CONE 
value used to determine the Variable Resource Requirement Curve, in accordance with Tariff, 
Attachment DD, section 5.10(a)(iv), and for all other resource types, the “BLS Producer Price 
Index Turbines and Turbine Generator Sets” component of the Applicable BLS Composite Index 
used to determine the Variable Resource Requirement Curve shall be replaced with the “BLS 
Producer Price Index Final Demand, Goods Less Food & Energy, Private Capital Equipment” 
when adjusting the gross costs of new entry.  The resultant value shall then be then adjusted 
further by a factor of 1.022 for nuclear, coal, combustion turbine, and combine cycle resource 
types or 1.01 for solar, wind, and storage resource types to reflect the annual decline in bonus 
depreciation scheduled under federal corporate tax law.  Updated estimates of the net energy and 
ancillary service revenues for each default resource type and applicable Zone, which shall 
include, but are not limited to, consideration of Fuel Costs, Maintenance Adders and Operating 
Costs, as applicable, pursuant to Operating Agreement, Schedule 2 shall then be subtracted from 
the adjusted gross costs of new entry to determine the adjusted New Entry MOPR Floor Offer 
Price.  The net energy and ancillary services revenue is equal to the average of the annual net 
revenues of the three most recent calendar years preceding the Base Residual Auction, where 
such annual net revenues shall be determined in accordance with the following and the PJM 
Manuals:   
 
(i) for nuclear resource type, the net energy and ancillary services 
revenue estimate shall be determined by the gross energy market revenue determined by the 
product of [average annual zonal day-ahead LMP, times 8,760 hours times the annual average 
equivalent availability factor of all PJM nuclear resources] minus the total annual cost to produce 
energy determined by the product of [8,760 hours times the annual average equivalent 
availability factor of all PJM nuclear resources times $9.02/MWh for a single unit plant or 
$7.66/MWh for a multi-unit plant] where these hourly cost rates include fuel costs and variable 
operation and maintenance expenses, inclusive of Maintenance Adder costs, plus an ancillary 
services revenue of $3,350/MW-year to be included through the 2025/2026 Delivery Year;  
 
(ii) for coal resource type, the net energy and ancillary services 
revenue estimate shall be determined by a simulated dispatch of a 650 MW coal unit (with heat

rate of 8,638 BTU/kWh and variable operations and maintenance variable operation and 
maintenance expenses, inclusive of Maintenance Adder costs, of $9.50/MWh) using applicable 
coal prices, as set forth in the PJM Manuals, plus reactive services revenue of $3,350/MW-year 
to be included through the 2025/2026 Delivery Year. The unit is committed day-ahead in 
profitable blocks of at least eight hours, and then committed in real-time for profitable hours if 
not already committed day ahead;  
 
(iii) for combustion turbine resource type, the net energy and 
ancillary services revenue estimate shall be determined in a manner consistent with the 
methodology described in Tariff, Attachment DD, section 5.10(a)(v)(B) for the Reference 
Resource combustion turbine.   
 
(iv) for combined cycle resource type, the net energy and ancillary 
services revenue estimate shall be determined in the same manner as that prescribed for a 
combustion turbine resource type, except that the heat rate assumed for the combined cycle 
resource shall be 6,553 BTU/kwh, the variable operations and maintenance expenses for such 
resource, inclusive of Maintenance Adder costs, shall be $2.11/MWh, the Peak-Hour Dispatch 
scenario for both the Day-Ahead and Real-Time Energy Markets shall be modified to dispatch 
the CC resource continuously during the full peak-hour period, as described in Peak-Hour 
Dispatch, for each such period that the resource is economic (using the test set forth in such 
section), rather than only during the four-hour blocks within such period that such resource is 
economic, and the ancillary services revenue shall be $3,350/MW-year to be included through 
the 2025/2026 Delivery Year.  
 
(v) for solar PV resource type, the net energy and ancillary services 
revenue estimate shall be determined using a solar resource model that provides the average MW 
output level, expressed as a percentage of nameplate rating, by hour of day (for each of the 24-
hours of a day) and by calendar month (for each of the twelve months of a year). The annual net 
energy market revenues are determined by multiplying the solar output level of each hour by the 
real-time zonal LMP applicable to such hour with this product summed across all of the hours of 
an annual period, plus an ancillary services revenue of $3,350/MW-year to be included through 
the 2025/2026 Delivery Year.  Two separate solar resource models are used, one model for a 
fixed panel resource and a second model for a tracking panel resource;  
 
(vi) for onshore wind resource type, the net energy and ancillary 
services revenue estimate shall be determined using a wind resource model that provides the 
average MW output level, expressed as a percentage of nameplate rating, by hour of day (for 
each of the 24-hours of a day) and by calendar month (for each of the twelve months of a year). 
The annual energy market revenues are determined by multiplying the wind output level of each 
hour by the real-time zonal LMP applicable to such hour with this product summed across all of 
the hours of an annual period, plus an ancillary services revenue of $3,350/MW-year to be 
included through the 2025/2026 Delivery Year; 
 
(vii) for offshore wind resource type, the net energy and ancillary 
services revenue estimate shall be the product of [the average annual zonal real-time LMP times 
8,760 hours times an assumed annual capacity factor of 45%], plus an ancillary services revenue 
of $3,350/MW-year to be included through the 2025/2026 Delivery Year; and

(viii) for Capacity Storage Resource, the net energy and ancillary 
services revenue estimate shall be estimated by a simulated dispatch against historical real-time 
zonal LMPs where the resource is assumed to be dispatched for the four hours of highest LMP of 
a daily twenty-four hour period if the average LMP of these four hours exceeds 120% of the 
average LMP of the four lowest LMP hours of the same twenty-four hour period.  The net energy 
market revenues will be determined by the product of [hourly output of 1 MW times the hourly 
LMP for each hour of assumed discharging] minus the product of [hourly consumption of 1.2 
MW times the hourly LMP for each hour of assumed charging] with this net value summed 
across all of the hours of an annual period, plus an ancillary services revenue of $3,350/MW-year 
to be included through the 2025/2026 Delivery Year.  An 83.3% efficiency of the battery energy 
storage resource is reflected by assuming each 1.0 MW of discharge requires 1.2 MW of charge.   
 
Beginning with the Delivery Year that commences June 1, 2022, and continuing no later than for 
every fourth Delivery Year thereafter, the Office of the Interconnection shall review the default 
gross cost of new entry values.  Such review may include, without limitation, analyses of the 
fixed development, construction, operation, and maintenance costs for such resource types.  
Based on the results of such review, PJM shall propose either to modify or retain the default 
gross cost of new entry values stated in the table above.  The Office of the Interconnection shall 
post publicly and solicit stakeholder comment regarding the proposal.  If, as a result of this 
process, changes to the default gross cost of new entry values are proposed, the Office of the 
Interconnection shall file such proposed modifications with the FERC by October 1, prior to the 
conduct of the Base Residual Auction for the first Delivery Year in which the new values would 
be applied.   
 
Any Generation Capacity Resource that is subject to the provisions of the Minimum Offer Price 
Rule pursuant to Tariff, Attachment DD, section 5.14(h-2)(2) and that has not previously cleared 
an RPM Auction for that or any prior Delivery Year and for which there is no default MOPR 
Floor Offer Price provided in accordance with this section, including hybrid resources, must seek 
a unit-specific value determined in accordance with the unit-specific MOPR Floor Offer Price 
process below to participate in an RPM Auction.  Failure to obtain a unit-specific MOPR Floor 
Offer Price will result in the Office of the Interconnection rejecting any Sell Offer based on such 
resource for the relevant RPM Auction. 
 
(B) 
Cleared MOPR Floor Offer Prices.   
 
For a Generation Capacity Resource that is subject to the 
provisions of the Minimum Offer Price Rule pursuant to Tariff, Attachment DD, section 5.14(h-
2)(2) and for which a Sell Offer based on that resource has previously cleared an RPM Auction 
for any Delivery Year, the applicable Cleared MOPR Floor Offer Price shall be, at the election of 
the Capacity Market Seller, (a) based on the unit-specific MOPR Floor Offer Price, as 
determined in accordance with Tariff, Attachment DD, section 5.14(h-2)(4) below, or (b) if 
available, the default Avoidable Cost Rate for the applicable resource type shown in the table 
below, as adjusted for Delivery Years subsequent for the 2022/2023 or 2026/2027 Delivery 
Year, as applicable, to reflect changes in avoidable costs, net of projected PJM market revenues 
equal to the resource’s historical net energy and ancillary service revenues consistent with Tariff, 
Attachment DD, section 6.8(d).

Existing Resource 
Type 
Through the 
2025/2026 Delivery 
Years:  
Default Gross ACR 
(2022/2023)  
($/MW-day) 
(Nameplate) 
For the 2026/2027 
Delivery Year and 
Subsequent Delivery 
Years:  
Default Gross ACR 
(2026/2027) ($/ MW-
day) Nameplate 
Nuclear - single 
$697 
$591 
Nuclear - dual 
$445 
$537 
Coal 
$80 
$94 
Combined Cycle 
$56 
$113 
Combustion Turbine 
$50 
$52 
Steam Oil & Gas 
NA 
$64 
Solar PV 
(fixed and tracking) 
$40 
$70 
Wind Onshore 
$83 
$147 
 
The default gross Avoidable Cost Rate values in the table above are expressed in dollars per 
MW-day in terms of nameplate megawatts.  Through the 2024/2025 Delivery Year, for purposes 
of submitting a Sell Offer, the default Avoidable Cost Rate values must be net of estimated net 
energy and ancillary service revenues, and then the difference is ultimately converted to 
Unforced Capacity (“UCAP”) MW-day, where the UCAP MW-day value will be determined 
based on the resource-specific Accredited UCAP value for solar and wind resource types (with 
appropriate time-weighting for any winter Capacity Interconnection Rights) or the resource-
specific EFORd for all other generation resource types.  Effective for the 2025/2026 Delivery 
Year and subsequent Delivery Years, for purposes of submitting a Sell Offer, the default 
Avoidable Cost Rate values must be net of estimated net energy and ancillary service revenues, 
and then the difference is ultimately converted to Unforced Capacity (“UCAP”) MW-day, based 
on the resource’s Accredited UCAP Factor. The resulting default Cleared MOPR Floor Offer 
price in UCAP/MW-day terms shall be applied to each MW offered for the Capacity Resource 
regardless of actual Sell Offer quantity and regardless of whether the Sell Offer is for a Seasonal 
Capacity Performance Resource. 
 
Commencing with the Base Residual Auction for the 2023/2024 Delivery Year, the Office of the 
Interconnection shall adjust the default Avoidable Cost Rates in the table above, and post the 
adjusted values on its website, by no later than one hundred fifty (150) days prior to the 
commencement of the offer period for each Base Residual Auction.  To determine the adjusted 
Avoidable Cost Rates, the Office of the Interconnection shall utilize the 10-year average Handy-
Whitman Index in order to adjust the Gross ACR values to account for expected inflation. 
Updated estimates of the net energy and ancillary service revenues shall be determined on a 
resource-specific basis in accordance with Tariff, Attachment DD, section 6.8(d) and the PJM 
Manuals.  
 
Beginning with the Delivery Year that commences June 1, 2022, and continuing no later than for 
every fourth Delivery Year thereafter, the Office of the Interconnection shall review the default

Avoidable Cost Rates for Capacity Resource that is subject to the provisions of the Minimum 
Offer Price Rule pursuant to Tariff, Attachment DD, section 5.14(h-2)(2) that have cleared in an 
RPM Auction for any Delivery Year.  Such review may include, without limitation, analyses of 
the avoidable costs of such resource types.  Based on the results of such review, PJM shall 
propose either to modify or retain the default Avoidable Cost Rate values stated in the table 
above.  The Office of the Interconnection shall post publicly and solicit stakeholder comment 
regarding the proposal.  If, as a result of this process, changes to the default Avoidable Cost Rate 
values are proposed, the Office of the Interconnection shall file such proposed modifications 
with the FERC by October 1, prior to the conduct of the Base Residual Auction for the first 
Delivery Year in which the new values would be applied.   
 
Any Generation Capacity Resource that is subject to the provisions of the Minimum Offer Price 
Rule pursuant to Tariff, Attachment DD, section 5.14(h-2)(2) and that has previously cleared an 
RPM Auction for any Delivery Year and for which there is no default MOPR Floor Offer Price 
provided in accordance with this section, including hybrid resources, must seek a unit-specific 
value determined in accordance with the unit-specific MOPR Floor Offer Price process below to 
participate in an RPM Auction.  Failure to obtain a unit-specific MOPR Floor Offer Price will 
result in the Office of the Interconnection rejecting any Sell Offer based on such resource.  
 
(4) 
Unit-Specific Exception.  A Capacity Market Seller intending to submit a 
Sell Offer in any RPM Auction for a Generation Capacity Resource that is subject to the 
provisions of the Minimum Offer Price Rule below the applicable default MOPR Floor Offer 
Price may, at its election, submit a request for a unit-specific exception for such Capacity 
Resource.  A Capacity Market Seller intending to submit a Sell Offer in any RPM Auction for a 
Generation Capacity Resource that is under a fact-specific review for Buyer-Side Market Power 
pursuant to Tariff, Attachment DD, section 5.14(h-2)(2)(B)(ii), and where the offer is below the 
applicable default MOPR Floor Offer Price may, at its election, submit a request for a unit-
specific exception for such Generation Capacity Resource.  A Sell Offer below the default 
MOPR Floor Offer Price, but no lower than the unit-specific MOPR Floor Offer Price, shall be 
permitted if the Capacity Market Seller obtains approval from the Office of the Interconnection 
or the Commission, prior to the RPM Auction in which it seeks to submit the Sell Offer. The 
unit-specific MOPR Floor Offer Price determined under this provision shall be based on the unit-
specific Accredited UCAP value for battery energy storage resource types and for solar and wind 
generation resource types (appropriately time-weighted for any winter Capacity Interconnection 
Rights) or on the unit-specific EFORd for all other generation resource types, and shall be 
applied to each MW offered by the resource regardless of actual Sell Offer quantity and 
regardless of whether the Sell Offer is for a Seasonal Capacity Performance Resource.  Such Sell 
Offer is permissible because it is consistent with the competitive, cost-based, fixed, net cost of 
the resource.  All supporting data must be provided for all requests.  The following requirements 
shall apply to requests for such determinations: 
 
(A) 
The Capacity Market Seller shall submit a written request with all 
of the required documentation as described below and in the PJM Manuals.  For such purpose, 
the Capacity Market Seller shall submit the unit-specific exception request to the Office of the 
Interconnection and the Market Monitoring Unit no later than one hundred twenty (120) days 
prior to the commencement of the offer period for the RPM Auction in which it seeks to submit 
its Sell Offer.  For such purpose, the Office of the Interconnection shall post, by no later than one

hundred fifty (150) days prior to the commencement of the offer period for the relevant RPM 
Auction, a preliminary estimate for the relevant Delivery Year of the default Minimum Floor 
Offer Prices, determined pursuant to Tariff, Attachment DD, sections 5.14(h-2)(3)(A) and (B).  If 
the final applicable default Minimum Floor Offer Price subsequently established for the relevant 
Delivery Year is less than the Sell Offer, the Sell Offer shall be permitted and no exception shall 
be required. 
 
(B) 
For a unit-specific exception for a Generation Capacity Resource 
that is subject to the provisions of the Minimum Offer Price Rule pursuant to Tariff, Attachment 
DD, section 5.14(h-2)(2) and that has never cleared an RPM Auction, the Capacity Market Seller 
must include in its request for an exception under this subsection documentation to support the 
fixed development, construction, operation, and maintenance costs of the Capacity Resource, as 
well as estimates of offsetting net revenues.   
 
The financial modeling assumptions for calculating Cost of New Entry for Generation Capacity 
Resources shall be: (i) nominal levelization of gross costs, (ii) asset life of twenty years, (iii) no 
residual value, (iv) all project costs included with no sunk costs excluded, (v) use first year 
revenues (which may include revenues from the sale of renewable energy credits or any other 
revenues outside of PJM markets that do not constitute Conditioned State Support ), and (vi) 
weighted average cost of capital based on the actual cost of capital for the entity proposing to 
build the Capacity Resource.  Notwithstanding the foregoing, a Capacity Market Seller that seeks 
to utilize an asset life other than twenty years (but no greater than 35 years) shall provide 
evidence to support the use of a different asset life, including but not limited to, the asset life 
term for such resource as utilized in the Capacity Market Seller’s financial accounting (e.g., 
independently audited financial statements), or project financing documents for the resource or 
evidence of actual costs or financing assumptions of recent comparable projects to the extent the 
seller has not executed project financing for the resource (e.g., independent project engineer 
opinion or manufacturer’s performance guarantee), or opinions of third-party experts regarding 
the reasonableness of the financing assumptions used for the project itself or in comparable 
projects.  Capacity Market Sellers may also rely on evidence presented in federal filings, such as 
its FERC Form No. 1 or an SEC Form 10-K, to demonstrate an asset life other than 20 years of 
similar asset projects. 
 
Supporting documentation for project costs may include, as applicable and available, a complete 
project description; environmental permits; vendor quotes for plant or equipment; evidence of 
actual costs of recent comparable projects; bases for electric and gas interconnection costs and 
any cost contingencies; bases and support for property taxes, insurance, operations and 
maintenance (“O&M”) contractor costs, and other fixed O&M and administrative or general 
costs; financing documents for construction-period and permanent financing or evidence of 
recent debt costs of the seller for comparable investments; and the bases and support for the 
claimed capitalization ratio, rate of return, cost-recovery period, inflation rate, or other 
parameters used in financial modeling.  In addition to the certification, signed by an officer of the 
Capacity Market Seller, the request must include a certification that the claimed costs accurately 
reflect, in all material respects, the seller’s reasonably expected costs of new entry and that the 
request satisfies all standards for a unit-specific exception hereunder.  The request also shall 
identify all revenue sources (exclusive of any Conditioned State Support or bilateral contracts 
that direct submission of an offer to lower RPM Auction clearing prices) relied upon in the Sell

Offer to offset the claimed fixed costs, including, without limitation, long-term power supply 
contracts, tolling agreements, evidence of compensation outside the PJM market not tied to 
Conditioned State Support or a bilateral contract that directs submission of an offer to lower 
RPM Auction clearing prices, or tariffs on file with state regulatory agencies, and shall 
demonstrate that such offsetting revenues are consistent, over a reasonable time period identified 
by the Capacity Market Seller, with the standard prescribed above.  In making such 
demonstration, the Capacity Market Seller may rely upon forecasts of competitive electricity 
prices in the PJM Region based on well-defined models that include fully documented estimates 
of future fuel prices, variable operation and maintenance expenses, which may include 
Maintenance Adders, energy demand, emissions allowance prices, and expected environmental 
or energy policies that affect the seller’s forecast of electricity prices in such region, employing 
input data from sources readily available to the public.  Documentation for net revenues also may 
include, as available and applicable, plant performance and capability information, including 
heat rate, start-up times and costs, forced outage rates, planned outage schedules, maintenance 
cycle, fuel costs and other variable operations and maintenance expenses, and ancillary service 
capabilities.  Any evaluation of net revenues should be consistent with Operating Agreement, 
Schedule 2, including, but not limited to, consideration of Fuel Costs, Maintenance Adders and 
Operating Costs, as applicable.   
 
(C) 
For a Unit-Specific Exception for a Generation Capacity Resource 
that is subject to the provisions of the Minimum Offer Price Rule pursuant to Tariff, Attachment 
DD, section 5.14(h-2)(2) and that has previously cleared an RPM Auction, the Capacity Market 
Seller shall submit a Sell Offer consistent with the unit-specific Market Seller Offer Cap process 
pursuant to Tariff, Attachment DD, section 6.8; except that the 10% uncertainty adder may not 
be included in the “Adjustment Factor.”  In addition and notwithstanding the requirements of 
Tariff, Attachment DD, section 6.8, the Capacity Market Seller may, at its election, include in its 
request for an exception under this subsection documentation to support projected energy and 
ancillary services markets revenues.  Such a request shall identify all revenue sources (exclusive 
of any Conditioned State Support or bilateral contracts that direct submission of an offer to lower 
RPM Auction clearing prices) relied upon in the Sell Offer to offset the claimed fixed costs, 
including, without limitation, long-term power supply contracts, tolling agreements, evidence of 
compensation outside of PJM markets not tied to Conditioned State Support or a bilateral 
contract that directs submission of an offer to lower RPM Auction clearing prices, or tariffs on 
file with state regulatory agencies, and shall demonstrate that such offsetting revenues are 
consistent, over a reasonable time period identified by the Capacity Market Seller, with the 
standard prescribed above.  In making such demonstration, the Capacity Market Seller may rely 
upon forecasts of competitive electricity prices in the PJM Region based on well-defined models 
that include fully documented estimates of future fuel prices, variable operation and maintenance 
expenses, energy demand, which may include Maintenance Adders, and emissions allowance 
prices, and expected environmental or energy policies that affect the seller’s forecast of 
electricity prices in such region, employing input data from sources readily available to the 
public.  Documentation for net revenues also may include, as available and applicable, plant 
performance and capability information, including heat rate, start-up times and costs, forced 
outage rates, planned outage schedules, maintenance cycle, fuel costs and other variable 
operations and maintenance expenses, and ancillary service capabilities.  Any evaluation of 
revenues should include, but would not be not limited to, consideration of Fuel Costs,

Maintenance Adders and Operating Costs, as applicable, pursuant to Operating Agreement, 
Schedule 2. 
 
 
(D) 
A Sell Offer evaluated at the unit-specific exception shall be 
permitted if the information provided reasonably demonstrates that the Sell Offer’s competitive, 
fixed, cost-based offer level is below the default MOPR Floor Offer Price, based on competitive 
cost advantages relative to the costs estimated by the default MOPR Floor Offer Price, including, 
without limitation, competitive cost advantages resulting from the Capacity Market Seller’s 
business model, financial condition, tax status, access to capital or other similar conditions 
affecting the applicant’s costs, or based on net revenues that are reasonably demonstrated 
hereunder to be higher than those estimated by the default MOPR Floor Offer Price.  Capacity 
Market Sellers shall demonstrate that claimed cost advantages or sources of net revenue that are 
irregular or anomalous, that do not reflect arm’s-length transactions, or that are not in the 
ordinary course of the Capacity Market Seller’s business are consistent with the standards of this 
subsection, and that out-of-market compensation is not tied to Conditioned State Support or a 
bilateral contract that directs submission of an offer to lower RPM Auction clearing prices.  
Failure to adequately support such claimed cost advantages or revenues so as to enable the 
Office of the Interconnection to make the determination required in this section will result in the 
elimination of consideration of the unsupported element(s) of a unit-specific exception by the 
Office of the Interconnection. 
 
(E)  
The Capacity Market Seller must submit a sworn, notarized 
certification of a duly authorized officer, certifying that the officer has personal knowledge of the 
unit-specific exception request and that to the best of his/her knowledge and belief: (1) the 
information supplied to the Market Monitoring Unit and the Office of Interconnection to support 
its request for an exception is true and correct; (2) the Capacity Market Seller has disclosed all 
material facts relevant to the request for the exception; and (3) the request satisfies the criteria for 
the exception.  
 
(F) 
The Market Monitoring Unit shall review, in an open and 
transparent manner with the Capacity Market Seller and the Office of the Interconnection, the 
information and documentation in support of the request and shall provide its findings whether 
the proposed Sell Offer is acceptable, in accordance with the standards and criteria hereunder, in 
writing, to the Capacity Market Seller and the Office of the  Interconnection by no later than 
ninety (90) days prior to the commencement of the offer period for such auction.  The Office of 
the Interconnection shall also review, in an open and transparent manner, all exception requests 
and documentation and shall provide in writing to the Capacity Market Seller, and the Market 
Monitoring Unit, its determination whether the requested Sell Offer is acceptable and if not it 
shall calculate and provide to such Capacity Market Seller, a minimum Sell Offer based on the 
data and documentation received, by no later than sixty-five (65) days prior to the 
commencement of the offer period for the relevant RPM Auction.  After the Office of the 
Interconnection determines with the advice and input of Market Monitor, the acceptable 
minimum Sell Offer, the Capacity Market Seller shall notify the Market Monitoring Unit and the 
Office of the Interconnection, in writing, of the minimum level of Sell Offer to which it agrees to 
commit by no later than sixty (60) days prior to the commencement of the offer period for the 
relevant RPM Auction, and in making such determination, the Capacity Market Seller may

consider the applicable default MOPR Floor Offer Price and may select such default value if it is 
lower than the unit-specific determination.  A Capacity Market Seller that is dissatisfied with any 
determination hereunder may seek any remedies available to it from FERC; provided, however, 
that the Office of the Interconnection will proceed with administration of the Tariff and market 
rules based on the lower of the applicable default MOPR Floor Offer Price and the unit-specific 
determination unless and until ordered to do otherwise by FERC.   
 
i) 
Capacity Export Charges and Credits 
 
(1) 
Charge 
 
Each Capacity Export Transmission Customer shall incur for each day of each Delivery Year a 
Capacity Export Charge equal to the Reserved Capacity of Long-Term Firm Transmission 
Service used for such export (“Export Reserved Capacity”) multiplied by (the Final Zonal 
Capacity Price for such Delivery Year for the Zone encompassing the interface with the Control 
Area to which such capacity is exported minus the Final Zonal Capacity Price for such Delivery 
Year for the Zone in which the resources designated for export are located, but not less than 
zero).  If more than one Zone forms the interface with such Control Area, then the amount of 
Reserved Capacity described above shall be apportioned among such Zones for purposes of the 
above calculation in proportion to the flows from such resource through each such Zone directly 
to such interface under CETO/CETL analysis conditions, as determined by the Office of the 
Interconnection using procedures set forth in the PJM Manuals.  The amount of the Reserved 
Capacity that is associated with a fully controllable facility that crosses such interface shall be 
completely apportioned to the Zone within which such facility terminates. 
 
(2) 
Credit 
 
To recognize the value of firm Transmission Service held by any such Capacity Export 
Transmission Customer, such customer assessed a charge under section 5.14(i)(1) above also 
shall receive a credit, comparable to the Capacity Transfer Rights provided to Load-Serving 
Entities under Tariff, Attachment DD, section 5.15.  Such credit shall be equal to the locational 
capacity price difference specified in section 5.14(i)(1) above times the Export Customer's 
Allocated Share determined as follows: 
 
Export Customer’s Allocated Share equals  
 
(Export Path Import * Export Reserved Capacity) / 
 
(Export Reserved Capacity + Daily Unforced Capacity Obligations of all LSEs in such Zone). 
 
Where: 
 
“Export Path Import” means the megawatts of Unforced Capacity imported into the export 
interface Zone from the Zone in which the resource designated for export is located.

If more than one Zone forms the interface with such Control Area, then the amount of Export 
Reserved Capacity shall be apportioned among such Zones for purposes of the above calculation 
in the same manner as set forth in subsection (i)(1) above.  
 
(3) 
Distribution of Revenues 
 
Any revenues collected from the Capacity Export Charge with respect to any capacity export for 
a Delivery Year, less the credit provided in subsection (i)(2) for such Delivery Year, shall be 
distributed to the Load Serving Entities in the export-interface Zone that were assessed a  
 
Locational Reliability Charge for such Delivery Year, pro rata based on the Daily Unforced 
Capacity Obligations of such Load-serving Entities in such Zone during such Delivery Year. If 
more than one Zone forms the interface with such Control Area, then the revenues shall be 
apportioned among such Zones for purposes of the above calculation in the same manner as set 
forth in subsection (i)(1) above.

6.6 
Offer Requirement for Capacity Resources 
 
 
(a) 
To avoid application of subsection (h) below, (1) all of the installed capacity of all 
Existing Generation Capacity Resources located in the PJM Region, and (2) all of the RBP 
UCAP MW that is committed in the Reliability Backstop Procurement through the term of the 
commitment, shall be offered by the Capacity Market Seller that owns or controls all or part of 
such resource (which may include submission as Self-Supply) in all RPM Auctions for each 
Delivery Year, less any amount determined by the Office of the Interconnection to be eligible for 
an exception to this RPM must-offer requirement, where installed capacity is determined as of 
the date on which bidding commences for each RPM Auction pursuant to Tariff, Attachment 
DD, section 5.6.6.  Beginning with the 2025/2026 Delivery Year and subsequent Delivery Years, 
a Planned Generation Capacity Resource associated with a notice of intent to offer submitted 
pursuant to Tariff, Attachment DD, section 5.5 shall be required to be offered by the Capacity 
Market Seller of such resource in the relevant RPM Auction. Through the 2024/2025 Delivery 
Year, the Unforced Capacity of such resources is determined using the EFORd value that is 
submitted by the Capacity Market Seller in its Sell Offer, which shall not exceed the maximum 
EFORd for that resource as defined in section 6.6(b). Starting with the 2025/2026 Delivery Year, 
the Unforced Capacity of such resource is determined using the effective Accredited UCAP 
Factor for that resource.  If a resource should be included on the list of Existing Generation 
Capacity Resources subject to the RPM must-offer requirement that is maintained by the Market 
Monitoring Unit pursuant to Tariff, Attachment M-Appendix, section II.C.1, but is omitted 
therefrom whether by mistake of the Market Monitoring Unit or failure of the Capacity Market 
Seller that owns or controls all or part of such resource to provide information about the resource 
to the Market Monitoring Unit, this shall not excuse such resource from the RPM must-offer 
requirement.  
 
 
(b) 
Through the 2024/2025 Delivery Year, for each Existing Generation Capacity 
Resource, a potential Capacity Market Seller must timely provide to the Market Monitoring Unit 
and the Office of the Interconnection all data and documentation required under this section 6.6 
to establish the maximum EFORd applicable to each resource in accordance with standards and 
procedures specified in the PJM Manuals.  The maximum EFORd that may be used in a Sell 
Offer for RPM Auctions held prior to the date on which the final EFORds used for a Delivery 
Year are posted, is the greater of (i) the average EFORd for the five consecutive years ending on 
the September 30 that last precedes the Base Residual Auction, or (ii) the EFORd for the 12 
months ending on the September 30 that last precedes the Base Residual Auction. 
 
Notwithstanding the foregoing, a Capacity Market Seller may request an alternate maximum 
EFORd for Sell Offers submitted in such auctions if it has a documented, known reason that 
would result in an increase in its EFORd, by submitting a written request to the Market 
Monitoring Unit and Office of the Interconnection, along with data and documentation required 
to support the request for an alternate maximum EFORd, by no later one hundred twenty (120) 
days prior to the commencement of the offer period for the Base Residual Auction for the 
applicable Delivery Year.  The Capacity Market Seller must address any concerns identified by 
the Market Monitoring Unit and/or the Office of the Interconnection regarding the data and 
documentation provided and attempt to reach agreement with the Market Monitoring Unit on the 
level of the alternate maximum EFORd by no later than ninety (90) days prior to the

commencement of the offer period for the Base Residual Auction for the applicable Delivery 
Year.  As further described in Tariff, Attachment M-Appendix, section II.C, the Market 
Monitoring Unit shall notify the Capacity Market Seller and the Office of the Interconnection in 
writing of its determination of the requested alternate maximum EFORd by no later than ninety 
(90) days prior to the commencement of the offer period for the Base Residual Auction for the 
applicable Delivery Year.  By no later than eighty (80) days prior to the commencement of the 
offer period for the Base Residual Auction for the applicable Delivery Year, the Capacity Market 
Seller shall notify the Office of the Interconnection and the Market Monitoring Unit in writing 
whether it agrees with the Market Monitoring Unit on the alternate maximum EFORd or, if no 
agreement has been reached, specifying the level of alternate maximum EFORd to which it 
commits.  If a Capacity Market Seller fails to request an alternate maximum EFORd prior to the 
specified deadlines, the maximum EFORd for the applicable RPM Auction shall be deemed to be 
the default EFORd calculated pursuant to this section. 
 
The maximum EFORd that may be used in a Sell Offer for Third Incremental Auction, and for 
Conditional Incremental Auctions held after the date on which the final EFORd used for a 
Delivery Year is posted, is the EFORd for the 12 months ending on the September 30 that last 
precedes the submission of such offers. 
 
 
(c) 
[Reserved for Future Use] 
 
 
(d) 
Through the 2024/2025 Delivery Year, in the event that a Capacity Market Seller 
and the Market Monitoring Unit cannot agree on the maximum level of the alternate EFORd that 
may be used in a Sell Offer for RPM Auctions held prior to the date on which the final EFORds 
used for a Delivery Year are posted, the Office of the Interconnection shall make its own 
determination of the maximum level of the alternate EFORd based on the requirements of the 
Tariff and the PJM Manuals, per Tariff, Attachment DD, section 5.8, by no later than sixty-five 
(65) days prior to the commencement of the offer period for the Base Residual for the applicable 
Delivery Year, and shall notify the Capacity Market Seller and the Market Monitoring Unit in 
writing of such determination. 
 
 
(e) 
Through the 2024/2025 Delivery Year, nothing in this section precludes the 
Capacity Market Seller from filing a petition with FERC seeking a determination of whether the 
EFORd complies with the requirements of the Tariff.   
 
 
(f) 
Through the 2024/2025 Delivery Year, notwithstanding the foregoing, a Capacity 
Market Seller may submit an EFORd  that it chooses for an RPM Auction held prior to the date 
on which the final EFORd used for a Delivery Year is posted, provided that (i) it has participated 
in good faith with the process described in this section 6.6 and in Tariff, Attachment M-
Appendix, section II.C, (ii) the offer is no higher than the level defined in any agreement reached 
by the Capacity Market Seller and the Market Monitoring Unit that resulted from the foregoing 
process, and (iii) the offer is accepted by the Office of the Interconnection subject to the criteria 
set forth in the Tariff and the PJM Manuals.   
 
 
(g) 
A Capacity Market Seller that owns or controls an existing generation resource in 
the PJM Region that is capable of qualifying as an Existing Generation Capacity Resource as of

the date on which bidding commences for an RPM Auction may not avoid the rule in subsection 
(a) or be removed from Capacity Resource status by failing to qualify as a Generation Capacity 
Resource, or by attempting to remove a unit previously qualified as a Generation Capacity 
Resource from classification as a Capacity Resource for that RPM Auction.  However, 
generation resource may qualify for an exception to the RPM must-offer requirement, as shown 
by appropriate documentation, if the Capacity Market Seller that owns or controls such resource 
demonstrates that it: (i) is reasonably expected to be physically unable to participate in the 
relevant Delivery Year; (ii) has a financially and physically firm commitment to an external sale 
of its capacity, or (iii) was interconnected to the Transmission System as an Energy Resource 
and not subsequently converted to a Capacity Resource.   
 
However, in any Delivery Year in which a Capacity Resource has committed RBP UCAP MW, 
through the Reliability Backstop Procurement such Capacity Resource shall not be eligible for an 
exception to the RPM must-offer requirement, under Tariff, Attachment DD, section 6.6A, based 
on having a financially and physically firm commitment to an external sale of its capacity. 
 
Notwithstanding the foregoing, nothing herein provides a defense to a claim of withholding, 
market manipulation, or the exercise of market power by any entity who is affiliated with or are 
under common ownership or control of a Capacity Market Seller that does not submit an offer 
for a Generation Capacity Resource that obtains an exception to the capacity must-offer 
requirement. 
 
 
In order to establish that a resource is reasonably expected to be physically unable to 
participate in the relevant auction as set forth in (i) above, the Capacity Market Seller must 
demonstrate that: 
 
A. It has a documented plan in place to retire the resource prior to or during the Delivery 
Year, and has submitted a notice of Deactivation to the Office of the Interconnection 
consistent with Tariff, Part V, section 113.1, without regard to whether the Office of the 
Interconnection has requested the Capacity Market Seller to continue to operate the 
resource beyond its desired deactivation date in accordance with Tariff, Part V, section 
113.2 for the purpose of maintaining the reliability of the PJM Transmission System and 
the Capacity Market Seller has agreed to do so; 
 
B. Significant physical operational restrictions cause long term or permanent changes to the 
installed capacity value of the resource, or the resource is under major repair that will 
extend into the applicable Delivery Year, that will result in the imposition of RPM 
performance penalties pursuant to Tariff, Attachment DD; 
 
C. The Capacity Market Seller is involved in an ongoing regulatory proceeding (e.g. – 
regarding potential environmental restrictions) specific to the resource and has received 
an order, decision, final rule, opinion or other final directive from the regulatory authority 
that will result in the retirement of the resource; or 
 
D. A resource considered an Existing Generating Capacity Resource because it cleared an 
RPM Auction for a Delivery Year prior to the Delivery Year of the relevant auction, but

which is not yet in service, is unable to achieve full commercial operation prior to the 
Delivery Year of the relevant auction.  The Capacity Market Seller must submit to the 
Office of the Interconnection and the Market Monitoring Unit a written sworn, notarized 
statement of a corporate officer certifying that the resource will not be in full commercial 
operation prior to the referenced Delivery Year. 
In order to establish that a resource has a financially and physically firm commitment to 
an external sale of its capacity as set forth in (ii) above, the Capacity Market Seller must 
demonstrate that it has entered into a unit-specific bilateral transaction for service to load located 
outside the PJM Region, by a demonstration that such resource is identified on a unit-specific 
basis as a network resource under the transmission tariff for the control area applicable to such 
external load, or by an equivalent demonstration of a financially and physically firm commitment 
to an external sale.  The Capacity Market Seller additionally shall identify the megawatt amount, 
export zone, and time period (in days) of the export. 
A Capacity Market Seller that seeks approval for an exception to the RPM must-offer 
requirement, for any reason other than the reason specified in Paragraph A above, shall first 
submit such request in writing, along with all supporting data and documentation, to the Market 
Monitoring Unit for evaluation, notifying the Office of the Interconnection by copy of the same, 
by no later than one hundred twenty (120) days prior to the commencement of the offer period 
for the applicable RPM Auction.   
 
In order to obtain an exception to the RPM must-offer requirement for the reason 
specified in Paragraph A above, a Capacity Market Seller shall first submit a preliminary 
exception request in writing, along with supporting data and documentation indicating the 
reasons and conditions upon which the Capacity Market Seller is relying in its analysis of 
whether to retire such resource, to the Market Monitoring Unit for evaluation, notifying the 
Office of the Interconnection by copy of the same, by no later than (a) the September 1 that last 
precedes the Base Residual Auction and (b) two hundred forty (240) days prior to the 
commencement of the offer period for the applicable Incremental Auction.  By no later than five 
(5) Business Days after the notification deadline for any such preliminary exception requests, the 
Office of the Interconnection will post on its website a summary of the number of megawatts of 
Generation Capacity Resources for which it has received notification of preliminary exception 
requests, on an aggregate basis by Zone and Locational Deliverability Area that comprises a 
subset of a Zone, as specified in the PJM Manuals. 
 
Thereafter, as applicable, such Capacity Market Seller shall by no later than (a) the 
December 1 that last precedes the Base Residual Auction for the applicable Delivery Year, or (b) 
one hundred twenty (120) days prior to the commencement of the offer period for the applicable 
Incremental Auction, either (a) notify the Office of the Interconnection and the Market 
Monitoring Unit in writing that it is withdrawing its preliminary exception request and 
explaining the changes to its analysis of whether to retire such resource that support its decision 
to withdraw, or (b) demonstrate that it has met the requirements specified under Paragraph A 
above.  By no later than five (5) Business Days after the notification deadline for such 
notification, the Office of the Interconnection will post on its website a revised summary of the 
number of megawatts of Generation Capacity Resources for which it has received requests for 
exceptions to the RPM must-offer requirement for the reason specified in Paragraph A above, on

an aggregate basis by Zone and Locational Deliverability Area that comprises a subset of a Zone, 
as specified in the PJM Manuals. 
A Capacity Market Seller that seeks to remove a Generation Capacity Resource from 
Capacity Resource status shall first submit a preliminary request in writing, along with 
supporting data and documentation indicating the reasons and conditions upon which the 
Capacity Market Seller is relying in its analysis of whether to remove the Capacity Resource 
status of such resource to the Market Monitoring Unit for evaluation, notifying the Office of the 
Interconnection by copy of the same, by no later than (a) the September 1 that last precedes the 
Base Residual Auction, and (b) two hundred forty (240) days prior to the commencement of the 
offer period for the applicable Incremental Auction.  By no later than five (5) Business Days 
after the notification deadline for any such preliminary requests, the Office of the 
Interconnection will post on its website a summary of the number of megawatts of Generation 
Capacity Resources for which it has received notification of preliminary requests, on an 
aggregate basis by Zone and Locational Deliverability Area that comprises a subset of a Zone, as 
specified in the PJM Manuals. 
 
Thereafter, as applicable, such Capacity Market Seller shall, by no later than (a) the 
December 1 that last precedes the Base Residual Auction for the applicable Delivery Year, or (b) 
one hundred twenty (120) days prior to the commencement of the offer period for the applicable 
Incremental Auction, notify the Office of the Interconnection and the Market Monitoring Unit in 
writing that it is either (a) withdrawing its preliminary request and explaining the changes to its 
analysis that support its decision to withdraw, or (b) confirming its preliminary decision to 
remove the Generation Capacity Resource from Capacity Resource status.  By no later than five 
(5) Business Days after the notification deadline for such notification, the Office of the 
Interconnection will post on its website a revised summary of the number of megawatts of 
Generation Capacity Resources for which it has received requests to remove its Capacity 
Resource status, on an aggregate basis by Zone and Locational Deliverability Area that 
comprises a subset of a Zone, as specified in the PJM Manuals. 
The Market Monitoring Unit shall analyze the effects of the proposed removal of a 
Generation Capacity Resource from Capacity Resource status with regard to potential market 
power issues and shall notify the Capacity Market Seller and the Office of the Interconnection in 
writing of its determination of the request to remove the Generation Capacity Resource from 
Capacity Resource status, and whether a market power issue has been identified, by no later than 
ninety (90) days prior to the commencement of the offer period for the applicable RPM Auction. 
Such notice shall include the specific market power impact resulting from the proposed removal 
of the Generation Capacity Resource from Capacity Resource status, as well as an initial 
assessment of any steps that could be taken to mitigate the market power impact. 
A Capacity Market Seller may only remove the Generation Capacity Resource from 
Capacity Resource status if (i) the Market Monitoring Unit has determined that the Generation 
Capacity Resource meets the applicable criteria set forth in Tariff, Attachment DD, sections 
5.6.6 and this section 6.6 and the Office of the Interconnection agrees with this determination, or 
(ii) the Commission has issued an order terminating the Capacity Resource status of the resource, 
or (iii) it is required as set forth in Tariff, Attachment DD, section 6.6A(c).  Any RBP Resource 
committed through the Reliability Backstop Procurement shall not be allowed to remove

Capacity Resource status for the portion of the resource with committed RBP UCAP MW 
through the term of such commitment.  Nothing herein shall require a Market Seller to offer its 
resource into an RPM Auction prior to seeking to remove a resource from Capacity Resource 
status, subject to satisfaction of this section 6.6.  A Generation Capacity Resource that is 
removed from Capacity Resource status shall no longer qualify as an Existing Generation 
Capacity Resource, and the Capacity Interconnection Rights associated with such facility shall 
be subject to termination in accordance with the rules described in Tariff, Part VI, section 
230.3.3. The Office of the Interconnection shall amend the applicable Interconnection Service 
Agreement or wholesale market participation agreement to reflect any such removal of the 
Capacity Interconnection Rights, and shall report the amended agreement to the Commission in 
the same manner as the original (e.g., FERC filing or Electronic Quarterly Reports). The Office 
of the Interconnection shall file the amended agreement unexecuted if the Interconnection 
Customer or wholesale market participant does not sign the amended Interconnection Service 
Agreement or wholesale market participation agreement. 
If the Capacity Market Seller disagrees with the Market Monitoring Unit’s determination 
of its request to remove a resource from Capacity Resource status or its request for an exception 
to the RPM must-offer requirement, it must notify the Market Monitoring Unit in writing, with a 
copy to the Office of the Interconnection, of the same by no later than eighty (80) days prior to 
the commencement of the offer period for the applicable RPM Auction.  After the Market 
Monitoring Unit has made its determination of whether a resource may be removed from 
Capacity Resource status, or whether the resource meets one of the exceptions thereto, and has 
notified the Capacity Market Seller and the Office of the Interconnection of the same pursuant to 
Tariff, Attachment M-Appendix, section II.C.4, the Office of the Interconnection shall approve 
or deny the request.  The request shall be deemed to be approved by the Office of the 
Interconnection, consistent with the determination of the Market Monitoring Unit, unless the 
Office of the Interconnection notifies the Capacity Market Seller and Market Monitoring Unit, 
by no later than sixty-five (65) days prior to the date on which the offer period for the applicable 
RPM Auction commences, that the request is denied. 
If the Market Monitoring Unit does not timely notify the Capacity Market Seller and the 
Office of the Interconnection of its determination of the request to remove a Generation Capacity 
Resource from Capacity Resource status or for an exception to the RPM must-offer requirement, 
the Office of the Interconnection shall make the determination whether the request shall be 
approved or denied, and will notify the Capacity Market Seller of its determination in writing, 
with a copy to the Market Monitoring Unit, by no later than sixty-five (65) days prior to the date 
on which the offer period for the applicable RPM Auction commences. 
After the Market Monitoring Unit and the Office of the Interconnection have made their 
determinations of whether a resource meets the criteria to qualify for an exception to the RPM 
must-offer requirement, the Capacity Market Seller must notify the Market Monitoring Unit and 
the Office of the Interconnection whether it intends to exclude from its Sell Offer some or all of 
the subject capacity on the basis of an identified exception by no later than sixty-five (65) days 
prior to the date on which the offer period for the applicable RPM Auction commences.  PJM 
does not make determinations of whether withholding of capacity constitutes market power.  A 
Generation Capacity Resource that does not qualify for submission into an RPM Auction 
because it is not owned or controlled by the Capacity Market Seller for a full Delivery Year is

not subject to the offer requirement hereunder; provided, however, that a Capacity Market Seller 
planning to transfer ownership or control of a Generation Capacity Resource during a Delivery 
Year pursuant to a sale or transfer agreement entered into after March 26, 2009 shall be required 
to satisfy the offer requirement hereunder for the entirety of such Delivery Year and may satisfy 
such requirement by providing for the assumption of this requirement by the transferee of 
ownership or control under such agreement.  
 
If a Capacity Market Seller doesn’t timely seek to remove a Generation Capacity 
Resource from Capacity Resource status or timely submit a request for an exception to the RPM 
must-offer requirement, the Generation Capacity Resource shall only be removed from Capacity 
Resource status, and may only be approved for an exception to the RPM must-offer requirement, 
upon the Capacity Market Seller requesting and receiving an order from FERC, prior to the close 
of the offer period for the applicable RPM Auction, directing the Office of the Interconnection to 
remove the resource from Capacity Resource status and/or granting an exception to the RPM 
must-offer requirement or a waiver of the RPM must-offer requirement as to such resource.   
 
 
(h) 
Any existing generation resource located in the PJM Region that satisfies the 
criteria in the definition of Existing Generation Capacity Resource as of the date on which 
bidding commences for the Base Residual Auction for a Delivery Year, that is not offered into 
such Base Residual Auction, and that does not meet any of the exceptions stated in the prior 
subsection (g): (i) may not participate in any subsequent Incremental Auctions conducted for 
such Delivery Year; (ii) shall not receive any payments under Tariff, Attachment DD, section 
5.14 for such Delivery Year for the capacity of such Generation Capacity Resources; and (iii) 
shall not be permitted to satisfy any LSE’s Unforced Capacity Obligation, or any entity’s 
obligation to obtain the commitment of Capacity Resources, for such Delivery Year.   
 
 
All generation resources located in the PJM Region that satisfy the criteria in the 
definition of Existing Generation Capacity Resource as of the date on which bidding commences 
for an Incremental Auction for a particular Delivery Year, but that did not satisfy such criteria as 
of the date that on which bidding commenced in the Base Residual Auction for that Delivery 
Year, that is not offered into that Incremental Auction, and that does not meet any of the 
exceptions stated in the prior subsection (g): (i) may not participate in any subsequent 
Incremental Auctions conducted for such Delivery Year; (ii) shall not receive any payments 
under Tariff, Attachment DD, section 5.14 for such Delivery Year for the capacity of such 
Generation Capacity Resources; and (iii) shall not be permitted to satisfy any LSE’s Unforced 
Capacity Obligation, or any entity’s obligation to obtain the commitment of Capacity Resources, 
for such Delivery Year. 
 
 
Any Planned Generation Capacity Resource associated with a notice of intent to offer 
into a particular RPM Auction that is not offered into the associated RPM Auction and all 
Existing Generation Capacity Resources that are offered into a Base Residual Auction or 
Incremental Auction for a particular Delivery Year but do not clear in such auction, that are not 
offered into each subsequent Incremental Auction, and that do not meet any of the exceptions 
stated in the prior subsection (g): (i) may not participate in any Incremental Auctions conducted 
for such Delivery Year subsequent to such failure to offer; (ii) shall not receive any payments 
under Tariff, Attachment DD, section 5.14 for such Delivery Year for the capacity of such

Generation Capacity Resources; and (iii) shall not be permitted to satisfy any LSE’s Unforced 
Capacity Obligation, or any entity’s obligation to obtain the commitment of Capacity Resources, 
for such Delivery Year. 
 
 
Any such Existing Generation Capacity Resources may also be subject to further action 
by the Market Monitoring Unit under the terms of Tariff, Attachment M and Tariff, Attachment 
M – Appendix. 
 
 
(i) 
In addition to the remedies set forth in subsections (g) and (h) above, if the 
Market Monitoring Unit determines that one or more Capacity Market Sellers’ failure to offer 
part or all of one or more existing generation resources, for which the Office of the 
Interconnection has not approved an exception to the RPM must-offer requirement, into an RPM 
Auction as required by this Section 6.6 would result in an increase of greater than five percent in 
any Zonal Capacity Price determined through such auction, and the Office of the Interconnection 
agrees with that determination, the Office of the Interconnection shall apply to FERC for an 
order, on an expedited basis, directing such Capacity Market Seller to participate in the relevant 
RPM Auction, or for other appropriate relief, and PJM will postpone clearing the auction 
pending FERC’s decision on the matter.  If the Office of the Interconnection disagrees with the 
Market Monitoring Unit’s determination and does not apply to FERC for an order directing the 
Capacity Market Seller to participate in the auction or for other appropriate relief, the Market 
Monitoring Unit may exercise its powers to inform Commission staff of its concerns and to seek 
appropriate relief. 
 
 
(j) 
An RBP Resource committed through the Reliability Backstop Procurement must 
offer all available committed RBP UCAP MW as a price-taker (i.e., $0/MW-day) into the 
applicable RPM Auctions pursuant to the capacity must offer requirements and exceptions set 
forth in Tariff, Attachment DD, sections 6.6 and 6.6A.  The applicable RPM Auctions shall be 
the Base Residual Auctions and Incremental Auctions conducted after an RBP Resource’s RBP 
UCAP MW have been committed through the Reliability Backstop Procurement and continuing 
for each subsequent Delivery Year through the end of the fixed 15-year term, except RBP UCAP 
MW for RBP Resources without a notice of intent to offer submitted pursuant to Tariff, 
Attachment DD, section 5.5 for the 2029/2030 Base Residual Auction, which shall have a must 
offer requirement beginning in the next RPM Auction, including but not limited to the 
2030/2031 Base Residual Auction and the 2029/2030 Second Incremental Auction .

6.6A Offer Requirement for Capacity Performance Resources 
 
 
(a) 
The installed capacity of every Existing Generation Capacity Resource located in 
the PJM Region that is capable (or that reasonably can become capable) of qualifying as a 
Capacity Performance Resource shall be offered as a Capacity Performance Resource by the 
Capacity Market Seller that owns or controls all or part of such resource (which may include 
submission as Self-Supply) in all RPM Auctions for each such Delivery Year, less any amount 
determined by the Office of the Interconnection to be eligible for an exception to the Capacity 
Performance Resource must-offer requirement, where installed capacity is determined as of the 
date on which bidding commences for each RPM Auction pursuant to Tariff, Attachment DD, 
section 5.6.6.  A Planned Generation Capacity Resource associated with a notice of intent to 
offer submitted pursuant to Tariff, Attachment DD, section 5.5 shall be required to be offered by 
the Capacity Market Seller of such resource in the relevant RPM Auction. 
 
 
(b) 
Determinations of EFORd, Accredited UCAP, and Unforced Capacity made 
under this Tariff, Attachment DD, section 6.6 as to a Generation Capacity Resource shall govern 
the offers required under this section as to the same Generation Capacity Resource.   
 
 
(c) 
Exceptions to the requirement in subsection (a) shall be permitted only for a 
resource which the Capacity Market Seller demonstrates is reasonably expected to be physically 
incapable of satisfying the requirements of a Capacity Performance Resource.  Through the 
2025/2026 Delivery Year, Intermittent Resources, Capacity Storage Resources, Hybrid 
Resources consisting exclusively of components that in isolation would be Intermittent 
Resources or Capacity Storage Resources, Demand Resources, and Energy Efficiency Resources 
shall not be required to offer as a Capacity Performance Resource, but shall not be precluded 
from being offered as a Capacity Performance Resource at a level that demonstrably satisfies 
such requirements.  Beginning with the 2026/2027 Delivery Year, Demand Resources shall not 
be required to offer as a Capacity Performance Resource, but shall not be precluded from being 
offered as a Capacity Performance Resource at a level that demonstrably satisfies such 
requirements.  Notwithstanding the foregoing, nothing herein provides a defense to a claim of 
withholding, market manipulation, or the exercise of market power by any entity who is 
affiliated with or are under common ownership or control of a Capacity Market Seller that does 
not offer Demand Resources into a Reliability Pricing Model Auction.  Exceptions shall be 
determined using the same timeline and procedures as specified in section 6.6.  
 
Effective with the 2023/2024 Delivery Year, Capacity Market Sellers seeking an 
exception for a Base Residual Auction on the basis that a resource is incapable of meeting the 
Capacity Performance Resource requirement shall include a documented plan with the 
submission of their request showing the steps the Capacity Market Seller intends to pursue for 
the resource to become physically capable of satisfying the requirements of a Capacity 
Performance Resource.  Such plan shall include (i) a timeline for design, permitting, 
procurement, and construction milestones, as applicable, where such timeline shall not exceed 
one Base Residual Auction exception, and (ii) evidence of corporate commitment (e.g., an SEC 
filing, a press release, or a letter from a duly authorized corporate officer indicating intent to 
make such investment).  Periodic updates on the progress, shall be provided by the Capacity 
Market Seller to the Office of the Interconnection and the Market Monitoring Unit for their

review by no later than (i) one hundred twenty (120) days prior to the commencement of the 
offer period for subsequent Incremental Auctions for the applicable Delivery Years, and (ii) the 
December 1 that last precedes subsequent Base Residual Auctions.  The Capacity Market Seller 
shall also immediately notify the Office of the Interconnection and the Market Monitoring Unit 
of any material changes to the plan that may occur.  Upon request by a Capacity Market Seller, a 
one year extension to the plan timeline shall be permissible only for delays not caused by the 
Capacity Market Seller, and that could not have been remedied through the exercise of due 
diligence by the Capacity Market Seller. In no event may an exception be requested by the 
Capacity Market Seller for more than two Base Residual Auctions. 
 
Failure to submit a documented plan, or lack of good faith effort by a Capacity Market 
Seller to make an Existing Generation Capacity Resource physically capable of meeting the 
requirements of a Capacity Performance Resource in accordance with a documented plan, shall 
result in the removal of the resource’s Capacity Resource status effective with the first future 
Delivery Year for which the resource was granted an exception, no earlier than the 2023/2024 
Delivery Year.   The Office of the Interconnection shall amend the applicable Interconnection 
Service Agreement or wholesale market participation agreement to reflect any such removal of 
the Capacity Interconnection Rights, and shall report the amended agreement to the Commission 
in the same manner as the original (e.g. FERC Filing or Electronic Quarterly Reports).  The 
Office of the Interconnection shall file the amended agreement unexecuted if the Interconnection 
Customer or wholesale market participant does not sign the amended Interconnection Service 
Agreement or wholesale market participation agreement. The required change in Capacity 
Resource status shall only apply to those Generation Capacity Resources that are shown to be 
physically incapable of satisfying the requirements of a Capacity Performance Resource. 
 
 
(d) 
A resource not exempted or excepted under subsection (c) hereof that is capable 
of qualifying as a Capacity Performance Resource and does not offer into an RPM Auction as a 
Capacity Performance Resource shall be subject to the same restrictions on subsequent offers, 
and other possible remedies, as specified in section 6.6. 
 
 
(e) 
An RBP Resource committed through the Reliability Backstop Procurement must 
offer all committed RBP UCAP MW as price-takers (i.e., $0/MW-day) into the applicable RPM 
Auctions pursuant to the capacity must offer requirements and exceptions set forth in Tariff, 
Attachment DD, sections 6.6 and 6.6A.  The applicable RPM Auction shall be the Base Residual 
Auctions conducted after an RBP Resource’s RBP UCAP MW have been committed through the 
Reliability Backstop Procurement and continuing for each subsequent Delivery Year through the 
end of the fixed 15-year term, except RBP UCAP MW for Capacity Performance Resources 
without a notice of intent to offer submitted pursuant to Tariff, Attachment DD, section 5.5 for 
the 2029/2030 Base Residual Auction, which shall have a must offer requirement beginning in 
the next RPM Auction, including but not limited to the 2030/2031 Base Residual Auction and 
the 2029/2030 Second Incremental Auction.

16. 
RELIABILITY BACKSTOP  
 
16.1. Purpose 
 
The Reliability Backstop provides a mechanism to resolve reliability criteria violations caused 
by: (a) lack of sufficient capacity committed through the Reliability Pricing Model Auctions; or 
(b) near-term transmission deliverability violations identified after the Base Residual Auction is 
conducted.  These backstop mechanisms are intended to guarantee that sufficient generation, 
transmission and demand response solutions will be available to preserve system reliability.  The 
backstop mechanisms are based on specific triggers that signal a need for a targeted solution to a 
reliability problem that was not resolved by the long-term commitment of Capacity Resources 
through Self-Supply or the Reliability Pricing Model Auctions.   
 
16.2 
Investigation of Capacity Shortfall 
 
Beginning with the 2032/2033 Delivery Year and thereafter, iIf the total Unforced Capacity of 
Capacity Resources committed for a Delivery Year following the Base Residual Auction equates 
to an installed reserve margin that is more than one percentage point lower than the approved 
PJM Region Installed Reserve Margin, the Office of the Interconnection shall investigate the 
cause for the shortage, and recommend corrective action, including, without limitation, adjusting 
the Cost of New Entry to the extent determined necessary by such investigation, or addressing 
other barriers to entry identified by such investigation.  No Reliability Backstop Auction will be 
conducted to address such a shortfall unless it occurs in the Base Residual Auctions for three 
consecutive Delivery Years beginning with the 2032/2033 Delivery Year and thereafter.  
 
16.3 
Triggering Conditions 
 
 
a) 
Either of the following two conditions will trigger reliability backstop measures 
provided in this section, as described below: 
 
i) 
If the total Unforced Capacity of all Capacity Resources committed 
through Self-Supply or the Base Residual Auctions for three consecutive Delivery Years 
beginning with the 2032/2033 Delivery Year and thereafter, equates to an installed reserve 
margin that is more than one percentage point lower than the approved PJM Region Installed 
Reserve Margin, the Office of the Interconnection will declare a capacity shortage and make a 
filing with FERC for approval to conduct a Reliability Backstop Auction.  Upon receipt of such 
approval, the Office of the Interconnection will conduct a Reliability Backstop Auction in 
accordance with ection 16.4 below. 
 
ii) 
If the total Unforced Capacity of all Base Load Generation Resources 
committed in a Base Residual Auction for a Delivery Year is less than the forecasted minimum 
hourly load calculated by the Office of the Interconnection for such Delivery Year, the Office of 
the Interconnection will investigate the cause of shortfall.  If such a shortfall occurs in the Base 
Residual Auctions for three consecutive Delivery Years beginning with the 2032/2033 Delivery 
Year and thereafter, the Office of the Interconnection shall declare a capacity shortage and make 
a filing with FERC for approval to conduct a Reliability Backstop Auction.  Upon receipt of such

approval, the Office of the Interconnection will conduct a Reliability Backstop Auction in 
accordance with section 16.4 below.  
 
 
b) 
In addition to the foregoing events that trigger reliability backstop measures, if a 
near-term, i.e., later in time than the conduct of the Base Residual Auction for a Delivery Year, 
transmission criteria violation caused by an announced generation resource deactivation is 
identified by the regional transmission reliability planning analysis performed by the Office of 
the Interconnection in accordance with Part V of this Tariff, the Office of the Interconnection 
will identify the necessary transmission upgrade. In accordance with such rules, such generation 
resource may remain in service until the transmission upgrade is installed.  No Reliability 
Backstop Auction will be conducted. 
 
16.4. Reliability Backstop Auction 
 
 
a) 
Scope of Auction  
 
The Office of the Interconnection shall conduct each Reliability Backstop Auction to commit 
additional Generation Capacity Resources, or in the case of an auction triggered by section 
16.3(a)(ii), additional Base Load Generation Resources to the PJM Region to resolve the system-
wide reliability criteria violation that triggered the need for such auction.  Capacity Resources 
committed in a Reliability Backstop Auction for a Delivery Year shall not include any Planned 
Generation Capacity Resources previously committed in the Base Residual Auction for such 
Delivery Year.  The Reliability Backstop Auction shall obtain commitments of additional 
Generation Capacity Resources (or, as applicable, additional Base Load Generation Resources) 
for a term of up to fifteen (15) Delivery Years.  If a Reliability Backstop Auction is required, the 
offer period for such auction shall commence, subject to FERC approval as specified above, no 
later than four months after the Base Residual Auction in which the third consecutive Capacity 
Resource shortfall occurs. Upon verification and notification by the PJM Board of Managers that 
a Reliability Backstop Auction is required, the Office of the Interconnection shall post 
notification that a Reliability Backstop Auction is to be held.  Upon such notification, the offer 
period shall commence, and shall remain open for six (6) months.  PJMSettlement shall be the 
Counterparty to the capacity transaction resulting from committed Capacity Resources clearing 
the Reliability Backstop Auction. 
 
 
b) 
Sell Offers 
 
Each Sell Offer shall specify the following information, as further specified in the PJM Manuals: 
 
• 
the minimum price in $/MW-day required by the Capacity Market Seller to 
provide additional Unforced Capacity from a Generation Capacity Resource (or 
from a Base Load Generation Resource, in the case of an auction triggered by 
section 16.3(a)(ii)) above; 
 
• 
the megawatts of Unforced Capacity to be provided by such resource;  
 
• 
the specific location of the proposed plant;

• 
all information required from a Generation Interconnection Customer by Tariff, 
Part IV and the PJM Manuals;  
 
• 
general plant technical specifications, as specified in the PJM Manuals; 
 
• 
the term of cost recovery (“Backstop Period”) requested, not to exceed 15 years; 
and   
 
• 
the first full Delivery Year for which such resource shall be available, which shall 
also be the first year of the Backstop Period. 
 
Each Generation Capacity Resource (or Base Load Generation Resource) accepted in a 
Reliability Backstop Auction shall comply with the procedures for new generation 
interconnection in Tariff, Part IV, and each such resource shall be responsible for satisfying all 
capability and deliverability requirements for Capacity Resources, pursuant to the Reliability 
Assurance Agreement.  
 
 
c) 
Submission of Sell Offers 
 
The Sell Offer period shall begin at 00:01 Eastern Prevailing Time on the date specified by the 
Office of the Interconnection in the notification posting and shall end at 23:59 Eastern Prevailing 
Time six calendar months after such date.  Sell offers shall be submitted during such period in 
writing to the Office of the Interconnection, and shall conform to the submission procedures as 
specified in the PJM Manuals.  The Office of the Interconnection shall confirm in writing the 
receipt of each Sell Offer, within two weeks after receipt of each such offer. 
 
 
d) 
Posting of Information by the Office of the Interconnection  
 
Upon notification by the PJM Board of Managers that a Reliability Backstop Auction will be 
conducted, the Office of the Interconnection shall post the following information: 
 
• 
System condition that necessitates a Reliability Backstop Auction; 
 
• 
Megawatt quantity of Unforced Capacity required from additional Generation 
Capacity Resources, or from additional Base Load Generation Resources;  
 
• 
Date by which the resources must be capable of delivering Unforced Capacity; 
 
• 
Any other required specifications for the additional Unforced Capacity sought 
through such auction. 
 
 
e) 
Conduct of the Reliability Backstop Auction 
 
 
 
i) 
Auction Clearing Procedure

The Reliability Backstop Auction shall select the Sell Offer or combination of Sell Offers that 
that satisfies the requirements posted by the Office of the Interconnection at the lowest offer 
price(s).  If more than one Sell Offer must be selected to satisfy the specified requirements, the 
Sell Offers shall be selected in rank order from lowest offer price to highest offer price until the 
requirement is satisfied.  In the event two or more Sell Offers specify the same offer price, and 
fewer than all of such offers are needed to satisfy the specified requirements, the Office of the 
Interconnection shall select the Sell Offer(s) proposing Generation Capacity Resource(s), or, as 
applicable, Base Load Generation Resource(s) that will best satisfy overall reliability 
requirements for the PJM Region, as determined by the Office of the Interconnection using 
transmission reliability analysis.  
 
 
 
ii) 
Market Settlement 
 
Pursuant to the agreement specified below, each Capacity Market Seller submitting a Sell Offer 
that is accepted in a Reliability Backstop Auction shall be paid by PJMSettlement the offer price 
in such Sell Offer for each MW-day in the Backstop Period, less any payments the Capacity 
Market Seller is entitled to receive pursuant to Tariff, Attachment DD, section 5 as a result of 
Sell Offers submitted with respect to such Generation Capacity Resource in any Base Residual 
Auction or Incremental Auction, including, without limitation, payments of Capacity Resource 
Clearing Prices (including for Self-Supply) and Resource Make-Whole Payments; and less any 
payments the Capacity Market Seller is entitled to receive for energy or ancillary services 
pursuant to Operating Agreement, Schedule 1 with respect to services provided by such resource, 
net of the Variable Operations and Maintenance costs of such resource, as determined in 
accordance with the PJM Manuals.  
 
PJM shall recover the costs of any such payments to Capacity Market Sellers for such resources 
through a charge, in addition to the Locational Reliability Charge, assessed on all LSEs in the 
PJM Region, pro rata based on each such LSE’s Daily Unforced Capacity Obligations in all 
LDAs in which such LSE serves load.  PJMSettlement shall be the Counterparty to the LSE’s 
obligation to pay, and payment of, such charges. 
 
 
 
iii) 
Standard Contract Provisions 
 
PJMSettlement, will enter into an agreement with each Capacity Market Seller that submitted an 
accepted Sell Offer in any Reliability Backstop Auction providing for the payments specified 
above.  Such agreement shall include the provisions and address the standards set forth in section 
16.4(b) above, and shall include such other terms and conditions as are customary in the 
industry, as specified in the PJM Manuals. 
 
 
f) 
FERC Approval  
 
Any such agreement shall provide that it shall be filed with FERC as a rate schedule pursuant to 
section 205 of the Federal Power Act, and that the effectiveness of such agreement shall be 
conditioned on receipt of FERC acceptance or approval of such agreement. 
 
16.5 
Must Offer into Base Residual Auction

All Capacity Market Sellers submitting a Sell Offer that is selected in a Reliability Backstop 
Auction must offer all Unforced Capacity of the Generation Capacity Resource underlying such 
Sell Offer into the Base Residual Auctions conducted subsequent to the Reliability Backstop 
Auction for all Delivery Years in the Backstop Period.  The Market Seller shall offer the 
Unforced Capacity of such resources into each such auction at zero price, and shall receive the 
Capacity Resource Clearing Price as determined in each such auction. 
 
16.6 
Reliability Backstop Resource Deficiency Charges 
 
 
(a) 
Any Capacity Market Seller that submits a Sell Offer that was selected in a 
Reliability Backstop Auction and that is not able to deliver in a Delivery Year all megawatts of 
Unforced Capacity specified in the selected Sell Offer, shall not receive any payments that such 
Capacity Market Seller otherwise would have been eligible to receive for such Delivery Year 
pursuant to the Reliability Backstop Auction. 
 
 
(b) 
Any Capacity Market Seller that submits a Sell Offer that was selected in a 
Reliability Backstop Auction and that fails to deliver all megawatts of Unforced Capacity 
specified in the selected Sell Offer at any time during the Backstop Period specified in such Sell 
Offer must refund all payments received by such Market Seller pursuant to section 16.4(b) 
above.

18.  
RELIABILITY BACKSTOP PROCUREMENT 
 
The Reliability Backstop Procurement or “RBP” is a one-time procurement, starting in 2026, to 
address resource adequacy challenges in the PJM Region arising from insufficient capacity 
committed through Reliability Pricing Model Auctions starting in the 2027/2028 Delivery Year.

18.1  Determination of Final RBP Target 
 
The Reliability Backstop Procurement is designed to procure sufficient RBP UCAP MW to meet 
the Final RBP Target.   
 
(a) 
Initial RBP Target  
The Initial RBP Target shall be a region-wide value equal to the UCAP MW quantity PJM clears 
short of the PJM Region Reliability Requirement for the 2028/2029 Delivery Year Base Residual 
Auction.   
 
(b) 
Final RBP Target  
The Final RBP Target shall be a PJM region-wide value equal to the Initial RBP Target minus 
the total PJM region-wide Qualifying RBP Offset UCAP MW and the unforced capacity 
obligation value of load that have successfully requested and obtained an opt-out pursuant to 
Tariff, Attachment DD, section 18.1(d).    
 
(c) 
Fixed Resource Requirement Entities 
Fixed Resource Requirement (“FRR”) Entities as of the 2028/2029 Delivery Year shall be 
excluded from the Reliability Backstop Procurement, including Initial and Final RBP Targets.   
To the extent an Electric Distributor zone/area that has RBP UCAP MW committed through the 
Reliability Backstop Procurement later becomes an FRR Service Area pursuant to RAA, 
Schedule 8.1.D, the Electric Distributor zone/area shall continue to be accountable for the RBP 
UCAP MW quantity committed through the Reliability Backstop Procurement.   
 
(d) 
Opt-Out  
When calculating the Final RBP Target, the Initial RBP Target shall also be decremented where 
the Electric Distributor’s zone/area has rates that are not regulated by the states and is unable to 
address cost allocation associated with capacity procured in the backstop. Such request by the 
Electric Distributor shall specify the associated MW quantity of load in the zone/area that will be 
opted-out of the Initial RBP Target and be accompanied by supporting documentation 
demonstrating an inability to address cost allocation associated with capacity procured in the 
backstop, along with written support for such opt-out from the relevant state governor, RERRA, 
and interconnection customer(s). The Initial RBP Target shall be further decremented, if 
requested by an Electric Distributor, by up to the associated MW quantity of load that 
participates in a peak shaving adjustment program where such Electric Distributor’s zone/area 
addresses their capacity needs through peak shaving adjustment programs that are codified in 
state law and that also meet the requirements of Tariff, Attachment DD-2.

18.2 
Qualifying RBP Offset UCAP MW   
 
(a) 
Qualifying RBP Offset UCAP MW is capacity that (i) has not previously 
supported a capacity commitment or been committed in an FRR Plan as of the commencement of 
the Reliability Backstop Procurement; and (ii) is supplied by a resource that satisfies each of the 
criteria set forth in Tariff, Attachment DD, section 18.2(b).   
 
(b) 
Resources Eligible to Supply Qualifying RBP Offset UCAP MW 
 
A resource eligible to supply Qualifying RBP Offset UCAP MW must have an expected 
commercial operation date, or is reasonably expected to be an Annual Demand Resource or DER 
Capacity Aggregation Resource that will be registered with the Office of the Interconnection and 
under a contract to perform based on PJM dispatch instructions, by no later than June 1, 2032 
and be: (i) a new build generation resource including new resources that obtain Capacity 
Interconnection Rights transferred from deactivated resources or resources that have announced 
deactivation as of April 10, 2026; (ii) the incremental capacity created by an uprate of existing 
Generation Capacity Resources, but only to the extent such incremental capacity is created 
through an increase in such Generation Capacity Resource’s installed capacity and increase in 
Capacity Interconnection Rights associated with that Generation Capacity Resource; (iii) the 
incremental capacity created by the utilization of Surplus Interconnection Service; (iv) 
repowering of a deactivated generation resource that deactivated prior to April 10, 2026; (v) 
incremental capacity, whether due to greater Unforced Capacity or a higher level of Capacity 
Interconnection Rights, created by an existing Generation Capacity Resource’s changing fuel 
type to a more efficient fuel type; or (vi) Planned Demand Resource or Planned DER Capacity 
Aggregation Resources, as described in the RAA, Schedule 6 and Schedule 6.2. 
 
(c) 
Evidence of Qualifying RBP Offset UCAP MW  
 
During the RBP bid submission window defined in Tariff, Attachment DD, section 18.4, Electric 
Distributors shall report the Qualifying RBP Offset UCAP MW in their respective zones/areas to 
the Office of the Interconnection in accordance with their requirements set forth in the Operating 
Agreement, section 11.3, and such report shall be accompanied by evidence of at least one of the 
following supporting materials.  Likewise, to the extent LSEs, interconnecting customers, large 
loads, Transmission Owners, or other entities report Qualifying RBP Offset UCAP MW to the 
Office of the Interconnection during such RBP bid submission window, the reported Qualifying 
RBP Offset UCAP MW must be accompanied with evidence of at least one of the following 
supporting materials: 
 
(i) 
Signed bilateral contracts for Qualifying RBP Offset UCAP MW for at 
least five Delivery Years with a commercial operation date prior to the start of the 
2032/2033 Delivery Year, and matched with load that has an executed electric service 
agreement or transmission service agreement, indicating that the load will be coming 
online in the 2027/2028 or 2028/2029 Delivery Year; 
 
(ii) 
Self-Supply generation that is in a Relevant Electric Retail Regulatory 
Authority (“RERRA”)-approved or accepted integrated resource plan with either

associated generation in the PJM interconnection queue or signed bilateral contracts for 
Qualifying RBP Offset UCAP MW for at least five Delivery Years with a commercial 
operation date prior to the start of the 2032/2033 Delivery Year, and matched with load 
that has an executed electric service agreement or transmission service agreement, 
indicating that the load will be coming online in the 2027/2028 or 2028/2029 Delivery 
Year; or 
 
(iii) 
Signed commitment between a Curtailment Service Provider or DER 
Aggregator and new load(s) that has an executed electric service agreement or 
transmission service agreement, indicating that the new load(s) will, in a MW quantity 
equal to MW quantity of the new load(s), either (a) participate as Annual Demand 
Resources or DER Capacity Aggregation Resources starting in the 2028/2029 Delivery 
Year Second Incremental Auction and continuing through the 2032/2033 Delivery Year, 
or (b) purchase replacement Qualifying RBP Offset UCAP MW that are eligible 
generation or storage resources.  
 
(d) 
To determine the quantity of any Qualifying RBP Offset UCAP MW that are 
verified by the Office of the Interconnection and used to decrement the Initial RBP Target, the 
Office of the Interconnection shall use the applicable ELCC Class Ratings from the Base 
Residual Auction associated with the 2028/2029 Delivery Year, or the estimated unit-specific 
UCAP value for resources with no ELCC Class Rating. 
 
(e) 
The total quantity of Qualifying RBP Offset UCAP MW verified by the Office of 
the Interconnection and used to decrement the Initial RBP Target total amount allowed for each 
zone/area will be capped at the Load Adjustment for each Electric Distributor zone/area amount 
of summer 2028 demand as set forth in the load forecast.

18.3 
 Cost Allocation of RBP Charges, Credits, and Shortfall Charges 
 
(a) 
Cost Allocation to Electric Distributor zone/area 
 
The Office of the Interconnection shall allocate the Initial RBP Target MW to each Electric 
Distributor’s zone/area using that zone/area’s pro-rata share of the difference between the 
forecasted Load Adjustments for the 2026/2027 Delivery Year and the 2028/2029 Delivery Year.     
 
The difference between the forecasted Load Adjustments for the 2026/2027 and the 2028/2029 
Delivery Years shall be reduced for the purpose of this calculation to the extent:  
 
(i) 
an Electric Distributor, LSE, Transmission Owner, or other entity provides 
the Office of Interconnection with evidence of Qualifying RBP Offset UCAP MW, in 
accordance with Tariff, Attachment DD, section 18.2 and as may be further set forth in 
the PJM Manuals; or  
 
(ii) 
an Electric Distributor zonee/area meets one of the opt-out provisions set 
forth in accordance with Tariff, Attachment DD, section 18.1(d). 
 
The resulting reduced MW, floored at zero, is used to calculate the zone/area’s assigned pro-rata 
share of the Final RBP Target MW.  The zone/area’s assigned share of the Final RBP Target 
MW shall remain constant throughout the fixed, 15-year term. 
 
The Office of the Interconnection shall allocate the total RBP Charges, assessed daily, to an 
Electric Distributor’s zone/area on a pro-rata basis using the zone/area’s assigned share of the 
total Final RBP Target MW across all zone/areas.  
 
(b) 
Cost Allocation to Load Serving Entities 
 
(i) 
The daily assessed RBP Charges allocated to each Electric Distributor 
zone/area shall be further allocated to each applicable LSE within that zone/area with an 
RBP Obligation (“RBO”) based on the LSE’s pro-rata share of the total RBP Obligation 
MW for the zone/area.    
 
(ii) 
The RBP Charge assessed daily to an LSE in a zone/area shall be the 
LSE’s daily reported RBO MW in the zone/area divided by the total RBO MW in the 
zone/area multiplied by total, daily RBP Charges allocated to the zone/area.   
 
(iii) 
The RBO MW shall be, where available, the state and/or RERRA-
determined allocation of cleared RBP UCAP MW to LSEs within each Electric 
Distributor’s zone/area, as reported by each Electric Distributor to the Office of the 
Interconnection, with the initial allocation reported no later than sixty (60) days prior to 
the 2028/2029 Delivery Year.  If no RBO MW are reported to the Office of the 
Interconnection in an Electric Distributor zone/area, PJM will allocate the RBP Charges 
for that zone/area to all load in the zone/area using each LSE’s ratio share of the Daily 
Unforced Capacity Obligation for the zone/area as determined in RAA, Schedule 8.

PJMSettlement shall be the Counterparty to each LSE’s obligation to pay, and payments 
of, RBP Charges.  
 
(iv) 
RBP Shortfall Charges will be allocated to LSEs as credits based on using 
the same pro-rata share of the RBP Charges, pursuant to RAA, Section 7.2B.

18.4  Scope of the Reliability Backstop Procurement  
 
The Office of the Interconnection shall conduct an RBP to commit RBP Resources up to the 
UCAP MW value to meet the Final RBP Target.  The Reliability Backstop Procurement offer 
submission window for RBP Sell Offers shall open for three weeks in 2026.  The clearing and 
selection process will take place thereafter and concluding six weeks following the close of the 
offer submission window.  The Office of the Interconnection shall notify RBP Sellers that 
receive a commitment as an RBP Resource as soon as practicable upon the conclusion of the 
RBP.  The Office of the Interconnection shall post specific dates on the PJM website prior to the 
commencement of the Reliability Backstop Procurement.     
 
RBP Sellers may submit RBP Sell Offers of RBP Resources supporting RBP UCAP MW into 
the Reliability Backstop Procurement.  PJMSettlement shall be the Counterparty to the 
transactions arising from the RBP.   
 
An RBP Sell Offer will be considered binding once any PJM-identified deficiencies are cured 
and until the conclusion of the Reliability Backstop Procurement and the underlying resource 
does not receive a commitment in the Reliability Backstop Procurement.   
 
The Reliability Backstop Procurement shall offer commitments for RBP UCAP MW for a fixed 
period of fifteen (15) Delivery Years, starting with the 2028/2029 Delivery Year.  Resources 
with a commercial operation date later than the 2028/2029 Delivery Year shall be committed for 
the remainder of the fifteen-year term of the Reliability Backstop Procurement commitment 
period, i.e. through the end of the 2042/2043 Delivery Year.

18.5  The Reliability Backstop Procurement Process 
 
(a) 
RBP Seller Eligibility to Participate and General Requirements for Resources 
Supporting RBP UCAP MW 
 
To be eligible to participate in the Reliability Backstop Procurement, an RBP Seller must meet 
the RBP credit requirements, set forth in Tariff, Attachment DD, section 18.8, with RBP Sell 
Offer(s) for RBP UCAP MW based on a resource that:  
 
(i) 
Has a commercial operation date, or is reasonably expected to be an 
Annual Demand Resource or DER Capacity Aggregation Resource that will be registered 
with the Office of the Interconnection and under a contract to perform based on PJM 
dispatch instructions, by no later than June 1, 2032, inclusive of any required Network 
Upgrades;  
 
(ii) 
Has not received a capacity commitment or been committed in an FRR 
Plan as of the commencement of the Reliability Backstop Procurement; 
 
(iii) 
Is not supplying Qualifying RBP Offset UCAP MW; 
 
(iv) 
To the extent the subject of a notice of intent for the 2028/2029 Base 
Residual Auction, must have offered and not cleared in the 2028/2029 Base Residual 
Auction; 
 
(v) 
To the extent the subject of a notice of intent for the 2029/2030 Base 
Residual Auction, must be offered into the 2029/2030 Base Residual Auction; and 
 
(vi) 
Meets the requirements in Tariff, Attachment DD, sections 18.5(b), 
18.5(c), or 18.5(d). 
 
(b) 
Generation or Energy Storage Resources as an RBP Resource 
 
To qualify as an RBP Resource, a generation or Energy Storage Resource that supplies RBP 
UCAP MW eligible to be offered into the Reliability Backstop Procurement shall be in the PJM 
Region or meet the requirements to pseudo-tie into the PJM Region in Tariff, Attachment DD, 
section 5.5A(b), must meet the requirements of Tariff, Attachment DD, section 18.5(a) and must 
be: 
 
(i) 
Composed of new Installed Capacity and new Maximum Facility Output; 
 
(ii) 
Supported by new Capacity Interconnection Rights (if located in the PJM 
Region) or Capacity Interconnection Rights transferred from a deactivated resource or a 
resource that announced deactivation as of April 10, 2026; and 
 
(iii) 
Consist of (1) new build; (2) incremental capacity created by an uprate of 
an existing Generation Capacity Resource’s or Energy Storage Resource’s installed

capacity and associated level of Capacity Interconnection Rights; or (3) repowering of a 
generation resource that had deactivated, or announced deactivation, on or before April 
10, 2026. 
 
(c) 
RBP Demand Resources 
 
To qualify as a Demand Resource that supplies RBP UCAP MW eligible to be offered into the 
Reliability Backstop Procurement, a Demand Resource must meet the requirements of Tariff, 
Attachment DD, sections 18.5(a), and:  
 
(i) 
Not be reliant on or composed of registered location(s) that previously 
supported a Demand Resource that provided capacity in a prior Delivery Year unless 
such location represents an incremental increase in capacity resulting from an investment 
in new generation or new storage resources at that location; and    
 
(ii) 
Identify, as part of its RBP Sell Offer, for the full length of the fixed term, 
the location(s) and associated participation contract(s). 
 
(d)  
RBP DER Aggregation Resources 
 
To qualify as a DER Capacity Aggregation Resource that supplies RBP UCAP MW eligible to 
be offered into the Reliability Backstop Procurement, a Planned DER Capacity Aggregation 
Resource must meet the requirements of Tariff, Attachment DD, sections 18.5(b) and:  
 
(i) 
Identify, as part of its RBP Sell Offer, for the length of the fixed term, the 
location(s) and associated participation contract(s).  
 
(e) 
RBP Sell Offers 
 
RBP Sell Offers for RBP UCAP MW shall specify an offer quantity in UCAP MW and an offer 
price in $/MW-day UCAP for each Delivery Year beginning with the first full Delivery Year in 
which the RBP UCAP MW is expected to provide capacity through the end of the fixed 15-year 
term.   
 
RBP Sellers will be responsible for all actual Network Upgrade costs as determined through the 
interconnection process, without subsequent adjustments to RBP Sell Offers.   
 
Each RBP Sell Offer shall include the following information for the RBP UCAP MW offered: 
 
(i) 
the MW of UCAP to be provided by such resource for each Delivery Year, 
where the maximum UCAP included in an RBP Sell Offer shall be limited to no greater 
than 120% of the resource type’s most recent maximum Preliminary ELCC Class Ratings 
for 2028/2029 through the last posted Delivery Year or based on the resource’s maximum 
estimated unit-specific ELCC ratings across such period for resources with no ELCC 
Class Rating, multiplied by the resource’s ICAP;

(ii) 
the price in $/MW-day UCAP for each Delivery Year beginning with the 
first full Delivery Year in which the RBP UCAP MW is expected to provide capacity 
through the end of the fixed 15-year term;         
 
(iii) 
the first full Delivery Year for which such resource shall be available and 
offering to provide capacity;  
 
(iv) 
all relevant documentation necessary for the Office of the Interconnection 
to evaluate whether the project satisfies the gating criteria, as set forth in Tariff, 
Attachment DD, section 18.5(f)(i). 
 
(f) 
Clearing Structure 
 
Following the closing date of bid solicitation for the Reliability Backstop Procurement in 
October 2026, the Office of the Interconnection shall complete the Reliability Backstop 
Procurement in two stages: (1) gating criteria evaluation and (2) selection assessment, with 
notification of finalized commitments posted prior to the Base Residual Auction for the 
2029/2030 Delivery Year. The Reliability Backstop Procurement shall be pay-as-bid.  
 
(i) 
Stage 1: Gating Criteria Evaluation 
 
A valid RBP Sell Offer shall include the information and evidence required by this 
section.  The Office of the Interconnection shall evaluate all RBP Sell Offers for 
compliance with this requirement.  Such evaluation shall be conducted by the Office of 
the Interconnection on a pass/fail basis.   
 
RBP Sell Offers that do not include the following information shall not proceed to 
selection assessment, provided, however, that the Office of the Interconnection shall 
provide the RBP Seller the opportunity to cure any identified deficiencies within five (5) 
calendar days. Notwithstanding, such opportunity to cure shall not extend past the close 
of the bid submission window of the Reliability Backstop Procurement. 
 
RBP Sell Offers for RBP Generation and/or Storage Capacity Resources must be 
accompanied by:   
 
(1) 
A critical path construction schedule and expected commercial 
operation date, with attestation, for the Office of the Interconnection to validate 
that RBP Sell Offers are for RBP UCAP MW with a feasible commercial 
operation date of June 1, 2032 or earlier;   
 
(A) 
With respect to a project in Transition Cycle #2 under 
Tariff, Part VII and earlier, such project must provide study information 
and timeline from its most current PJM study;  
 
(B) 
With respect to a project in Cycle 1 under Tariff Part VIII, 
the Expedited Interconnection Track under Tariff, Part X, or not under

study, the project must provide study information and timeline from an 
independent consultant report; 
 
(2) 
Evidence of 100% Site Control for each of the Generating Facility 
(including the location of the main step-up transformer), the Interconnection 
Facilities, and the Interconnection Switchyard (as defined in the PJM Manuals) 
for a term of at least three years from the date of submission of the Application. 
 
In addition, a certification, executed by an officer or authorized representative of 
the Generation Project Developer, verifying that the Site Control requirements 
have been met. Further, at Transmission Provider’s request, Generation Project 
Developer shall provide copies of landowner attestations or county recordings. 
The Site Control requirements include an acreage requirement for the Project, as 
set forth in the PJM Manuals.  
 
Evidence of site control shall be consistent with Tariff, Part VIII, Subpart A, 
section 402;  
 
(3) 
Financing plan, i.e., identified financing sources and details (e.g., 
project financing, balance sheets, tax equity, sponsor equity), current status of any 
financing commitments or term sheets, and a general description of the capital 
structure and expected timeline to financial close; 
 
(4) 
Permitting plan, e.g., a list of all applicable permits, current status, 
and timeline to obtain each; 
 
(5) 
Signed memorandum for the acquisition of major equipment, 
invoices or agreements to acquire major equipment, or other documentary 
evidence that major equipment has been procured; 
 
(6) 
Evidence of experience having constructed a previous project of 
similar size and technology or have contracted with an engineering, procurement, 
and construction partner with such experience, or contract with an engineering, 
procurement, and construction partner with such experience; 
 
(7) 
For natural gas-fueled generation resources, evidence of delivery 
infrastructure arrangements in the form of a notice of intent or attestation of 
pipeline capacity expansion to support the new project; and 
 
(8) 
For generation and/or energy storage resources located outside of 
the PJM Region, evidence of (a) a completed facilities study or equivalent under 
the host Regional Transmission Organization/Independent System Operator’s or 
utility’s interconnection process and (b) long-term firm point-to-point 
transmission service, or a confirmed transmission service request with a 
completed system impact study, sufficient to deliver capacity to the border of the

PJM Region consistent with the requirements of Tariff, Attachment DD, section 
5.5A(b). 
 
RBP Sell Offers for Demand Resources or DER Capacity Aggregation Resources must 
be accompanied by: 
 
(9) 
Locations within the PJM Region by Zone/Sub-zonal LDA and 
aggregate capacity for RBP Sell Offers; 
 
(10) 
Executed customer agreements or binding commitments covering 
the proposed RBP UCAP MW commitment, with identified locations, customer 
names, and expected curtailment/injection capability per site; and 
 
(11) 
Equipment procurement plan or evidence of deployed enabling 
infrastructure such as metering, telemetry, load control, SCADA/dispatch 
systems, or DER major equipment as applicable. 
 
RBP Sell Offers for DER Capacity Aggregation Resources must also be accompanied by: 
 
(12) 
Applicable Electric Distributor interconnection/distribution impact 
study requirements and a plan to initiate on a timeline consistent with the 
proposed delivery date.  
 
RBP Sell Offers for Demand Resources must also be accompanied by: 
 
(13) 
Electric Distributor coordination requirements for metering, 
telemetry, and baseline measurement infrastructure. 
 
(ii) 
Stage 2: Selection Assessment 
 
All RBP Sell Offers that pass the gating criteria evaluation shall be evaluated based on 
the first Delivery Year offered in the RBP Sell Offer, levelized cost, and RBP UCAP 
MW quantity.   
 
RBP Sell Offers shall be selected in rank order from earliest to latest offered Delivery 
Year, and then in least-cost order based on the levelized cost ($/MW-day) of UCAP MW 
over the fixed 15-year term, until the Final RBP Target is satisfied for any Delivery Year 
up through the 2032/2033 Delivery Year.  RBP Resources shall not be partially cleared.  
In selecting the least-cost solution that satisfies the Final RBP Target and the cost of 
procurement constraint, the Office of the Interconnection may commit an RBP Sell Offer 
with an offered quantity that exceeds the remaining Final RBP Target to the extent such 
solution provides greater economic efficiency than an alternative solution that satisfies 
the requirements and constraints. 
 
The levelized cost of each RBP Sell Offer shall be calculated as:

Levelized Cost ($/MW-day) = Net Present Value (RBP Sell Offer price x UCAP 
offered)/Net Present Value (UCAP offered) 
 
with a discount rate equal to 9.5% after-tax average weighted average cost of capital 
(ATWACC). 
 
The MW-weighted average of the levelized procurement cost of all selected RBP Sell 
Offers shall not exceed $555/MW-day UCAP. 
 
In the event that two or more RBP Sell Offers with the same initial offered Delivery Year 
and levelized cost, and fewer than all of such offers are needed to satisfy the Final RBP 
Target, the Office of the Interconnection shall select the RBP Sell Offer(s) proposing 
resources based on the earliest timestamp of such RBP Sell Offer(s). 
 
In the event that the Reliability Backstop Procurement cannot meet the Final RBP Target, 
the Reliability Backstop Procurement shall clear short of the Final RBP Target.   
 
(g) 
Settlement Structure 
 
(i) 
UCAP MW Eligible to Be Settled as Contract for Difference 
 
 
Each RBP Resource that has been committed in the Reliability Backstop Procurement 
shall be individually settled as a contract for difference (“CfD”).   
 
An RBP Resource’s total daily MW eligible to be settled as a CfD shall be the lesser of 
the RBP Resource’s daily committed RBP UCAP MW, daily owned UCAP MW, and 
daily cleared RPM UCAP MW.  
 
All UCAP MW of an RBP Resource above the committed RBP UCAP MW shall be 
eligible to participate in RPM Auctions, subject to existing RPM rules, without being 
subject to RBP obligations or settlement. 
 
(ii) 
RBP Settlement Credits Based on Contract for Difference  
 
An RBP Resource’s contract for difference (“CfD”), represented as positive or negative 
RBP Settlement Credits, shall be settled daily as the product of the total daily UCAP MW 
eligible to settle as CfD and the difference between the price at which the RBP Resource 
was committed in the Reliability Backstop Procurement for a Delivery Year and the RBP 
Resource’s unit-specific weighted average resource clearing price of all applicable RPM 
Auctions from the associated Delivery Year.  Applicable RPM Auctions include all RPM 
Auctions for the associated Delivery Year that are conducted after the Reliability 
Backstop Procurement.  If the RBP Resource is committed through the RBP for a 
Delivery Year in which PJM has already conducted the Base Residual Auction, the CfD 
will be settled using the difference between the price at which the RBP Resource was 
committed in the Reliability Backstop Procurement for such Delivery Year and the

weighted average resource clearing price in the applicable Incremental Auction(s) for 
such Delivery Year. 
 
(iii) 
RBP Charges  
 
RBP Charges shall be based on the total RBP Settlement Credits, positive and negative, 
of all RBP Resources across the PJM Region.   
 
RBP Charges shall be calculated daily and allocated to Load Serving Entities by the 
relevant Electric Distributor(s) in accordance with Tariff, Attachment DD, section 
18.3(b) and the RAA, Article 7, section 2B.

18.6 
RBP Resource Obligations  
(a) 
Capacity Must Offer Obligation  
 
An RBP Resource committed through the Reliability Backstop Procurement must offer all 
committed RBP UCAP MW into the RPM Auctions as Capacity Resources pursuant to the 
capacity must offer requirements and exceptions set forth in Tariff, Attachment DD, sections 6.6 
and 6.6A. The applicable RPM auctions shall be the Base Residual Auctions and Incremental 
Auctions conducted after an RBP Resource’s RBP UCAP MW have been committed through the 
Reliability Backstop Procurement and continuing for each subsequent Delivery Year through the 
end of the fixed 15-year term, except RBP UCAP MW for RBP Resources without a notice of 
intent to offer submitted pursuant to Tariff, Attachment DD, section 5.5 for the 2029/2030 Base 
Residual Auction shall have a must offer requirement in the next RPM Auction, including but 
not limited to the 2030/2031 Base Residual Auction and the 2029/2030 Second Incremental 
Auction.  The RBP Resource’s capacity must offer obligation into RPM Auctions for a Delivery 
Year is satisfied once the entirety of the committed RBP UCAP MW have cleared in RPM 
Auction(s) for such Delivery Year.    
 
RBP Resources with RBP UCAP MW committed through RPM Auctions will be subject to all 
RPM capacity market rules, as set forth in Tariff, Attachments DD and DD-1.  
 
(i) 
Price  
 
RBP UCAP MW committed through the Reliability Backstop Procurement, and not 
qualifying for an exception pursuant to Tariff, Attachment DD, section 6.6(g), must be 
offered into the applicable RPM Auctions as price takers, i.e., $0/MW-day UCAP.  
 
(ii) 
Quantity 
 
RBP Resources committed through the Reliability Backstop Procurement must be offered 
into the applicable RPM Auctions.  The UCAP MW quantity offered in an applicable 
RPM Auction for the Delivery Year must be a quantity equal to the lesser of committed 
RBP UCAP MW minus total RPM committed MW through RPM Auctions for the 
Delivery Year and the available UCAP MW at the time of the RPM Auction.   
 
(b) 
Exceptions to the Must Offer Obligation 
 
An RBP Resource that is granted an exception to the RPM must-offer obligation, as set forth in 
Tariff, Attachment DD, section 6.6(g) or 6.6A(c), shall nevertheless be subject to the RBP 
shortfall charge.   
 
(c) 
RBP Shortfall UCAP MW 
 
RBP UCAP MW committed through the Reliability Backstop Procurement that is unable to be 
delivered in a Delivery Year within the fixed, 15-year period will not be compensated for the 
undelivered megawatts via RBP Settlement Credits for each day the daily unforced capacity

value of the RBP Resource is below the daily committed RBP UCAP MW and will be subject to 
any applicable RBP shortfall charges. 
 
(d) 
RBP Shortfall Charges  
 
RBP Resources with RBP UCAP MW committed through the Reliability Backstop Procurement 
that are unable to meet its full RBP UCAP MW commitment due to not achieving commercial 
operation by the first Delivery Year of the RBP commitment shall be subject to RBP shortfall 
charges for the committed RBP UCAP MW until the resources achieves commercial operation, 
for up to three years.   
 
RBP shortfall charges shall be assessed daily, beginning in the first Delivery Year of the RBP 
commitment, on the full RBP committed UCAP.  
 
The RBP shortfall charge shall equal the committed RBP UCAP MW times a charge rate equal 
to 20% of the RBP commitment price of such resource (i.e., RBP shortfall charge = committed 
RBP UCAP MW * 20% of RBP commitment price), for the applicable Delivery Year 
 
(i) 
Exception to RBP Shortfall Charges 
 
An RBP Resource that is a generation or Energy Storage Resource and is unable to meet 
expected commercial operation date solely due to Network Upgrades shall be excepted 
from RBP shortfall charges if the RBP Resource successfully demonstrates readiness 
through test energy and seeks interim deliverability. 
 
(e) 
Failure of RBP UCAP MW to Materialize 
 
Commitments of RBP UCAP MW through the Reliability Backstop Procurement shall be 
rescinded for the remainder of the fifteen-year term where RBP UCAP MW fail to come online 
for three Delivery Years beginning with the first Delivery Year in which the RBP Resource was 
committed.  Once rescinded, RBP UCAP MW commitments will not be eligible to be 
compensated as RBP UCAP MW for the remainder of the fixed 15-year term and shall no longer 
be subject to RBP shortfall charges.    
 
(f) 
Change in Ownership 
 
Commitments of RBP UCAP MW shall follow the RBP Resource.  With change in ownership of 
the RBP Resource, the commitment of RBP UCAP MW shall be conveyed to the new owner and 
continue through the end of the fixed 15-year term.

18.7 
Exiting Transmission Owner RBP Obligations 
 
In the event a Transmission Owner exits PJM Interconnection, L.L.C. and the quantity of load 
with the Transmission Owner is commensurate with the RBP Resources that are located in that 
Transmission Owner’s territory, the Transmission Owner shall honor the remaining term of the 
RBP commitment. 
 
(a) 
Exiting Transmission Owner with Committed RBP Resources  
 
Any Transmission Owner seeking to exit PJM Interconnection, L.L.C. may, prior to exiting PJM, 
enter into agreements that maintain appropriate rates, terms, and conditions that preserves the 
RBP commitments with the owners of RBP Resource(s) that have been committed through the 
Reliability Backstop Procurement that are located within the physical boundaries of the 
Transmission Owner’s Zone.  PJM and PJMSettlement shall be relieved of any applicable RBP 
obligations made to RBP Resources that are subject to such agreements. In the event no such 
agreement is made and such RBP Resource(s) can be pseudo-tied into the PJM Region, the 
exiting Transmission Owner must, to the extent the Office of the Interconnection elects to retain 
such RBP Resource throughout the term of its RBP commitment, pay all costs for RBP 
Resources to pseudo-tie into the PJM Region so that such resource meets the external Capacity 
Resource eligibility requirements set forth in Tariff, Attachment DD, section 5.5A prior to the 
Transmission Owner exiting PJM Interconnection, L.L.C. 
 
Any Transmission Owner seeking to exit PJM Interconnection, L.L.C. with RBP Resource(s) 
that (i) are located within the physical boundaries of the Transmission Owner’s Zone and (ii) 
cannot be pseudo-tied into the PJM Region, and/or which the Office of the Interconnection elects 
not to retain the RBP Resource as a Capacity Resource throughout the term of its RBP 
commitment, shall pay costs associated with the remaining term of the RBP Resource, the 
amount which shall be determined through a filing submitted under the Federal Power Act, prior 
to exiting PJM Interconnection, L.L.C.  Revenues collected in such an event shall be credited to 
Load Serving Entities that are allocated a share of the RBP Charges on a pro rata basis through 
the remaining term of the RBP commitment. 
 
(b) 
Exiting Transmission Owner with Load Allocated RBP Charges 
 
Any Transmission Owner seeking to exit PJM Interconnection, L.L.C. with net load that has 
been allocated RBP Charges for RBP Resources not located within the physical boundaries of 
the Transmission Owner’s Zone may, prior to exiting PJM, enter into agreements that maintain 
appropriate rates, terms and conditions that preserves the RBP commitments with the owners of 
such RBP Resource(s). PJM and PJMSettlement shall be relieved of any applicable RBP 
obligations made to RBP Resources that are subject to such agreements. In the event no such 
agreement is made, the exiting Transmission Owner must pay all forward obligations on an 
accelerated basis, the amount which shall be determined through a filing submitted under the 
Federal Power Act, prior to exiting PJM Interconnection, L.L.C.  Any such revenues collected 
shall be distributed to the RBP Resources under the standard daily RBP settlement schedule to 
such resources through the remaining term of the RBP commitment.

18.8 Credit Requirements for RBP Sellers and LSEs Allocated RBP Charges 
 
The provisions of Tariff, Attachment DD, section 18.8(a) shall apply to RBP Sellers seeking to 
submit RBP Sell Offers in the Reliability Backstop Procurement.  The provisions of Tariff, 
Attachment DD, section 18.8(b) shall apply to LSEs allocated costs for RBP UCAP MW 
procured through the Reliability Backstop Procurement, as determined in accordance with Tariff, 
Attachment DD, section 18.3.  Nothing in this Tariff, Attachment DD, section 18 supersedes the 
provisions of Tariff, Attachment Q.   
 
In addition, settlement during any Delivery Year of cleared positions resulting from, or expected 
to result from, the Reliability Backstop Procurement may be included, as appropriate, in Peak 
Market Activity pursuant to Tariff, Attachment Q, Section VII.A.  The forms of acceptable credit 
support shall be limited to RBP Collateral. 
 
The Reliability Backstop Procurement credit requirements described herein shall be separate 
from and additional to any credit requirements for participation in RPM Auctions and bilateral 
transactions under Tariff, Attachment DD, section 4.6, and other market activity in the PJM 
Markets, as set forth in Tariff, Attachment Q, and shall be applied separately to each RBP Seller 
with RBP Sell Offer and each LSE allocated cost for RBP UCAP MW procured through the 
Reliability Backstop Procurement, as determined in accordance with Tariff, Attachment DD, 
section 18.3.   
 
(a) 
RBP Credit Requirements of RBP Sellers Seeking to Submit RBP Sell Offers  
 
Prior to or simultaneous with submitting RBP Sell Offers, RBP Sellers seeking to participate in 
the Reliability Backstop Procurement must post the appropriate amount of the Reliability 
Backstop Procurement credit requirement to each RBP Resource for which RBP Sell Offers are 
submitted.   
 
(i) 
Applicability 
 
An RBP Seller seeking to submit an RBP Sell Offer in the Reliability Backstop 
Procurement must satisfy the credit requirement, i.e., the RBP credit requirement 
specified herein, prior to or simultaneously with submitting such RBP Sell Offer.   
 
(ii) 
RBP Resource Credit Requirement  
 
The credit requirement applicable to an RBP Seller seeking to submit an RBP Sell Offer 
in the Reliability Backstop Procurement shall be the RBP credit requirement as provided 
in Tariff, Attachment DD, section 18.8(iv).  
 
The total RBP credit requirement for each RBP Seller shall be, for the sum of the credit 
requirements for all RBP Sell Offers submitted by such RBP Seller in the Reliability 
Backstop Procurement.   
 
(iii) 
Reduction in RBP Credit Requirement

(A) 
The RBP credit requirement shall be returned for any RBP 
Resources that do not receive a commitment through the Reliability Backstop 
Procurement, within five (5) business of the completion of the clearing process 
pursuant to Tariff, Attachment DD, section 18.5(f).     
 
(B) 
Where an RBP Seller’s RBP Sell Offer is committed through the 
Reliability Backstop Procurement and the RBP Resource subsequently achieves 
commercial operation, the Office of the Interconnection may return the Reliability 
Backstop Procurement Credit Requirement after a one-year look-back from the 
achievement of commercial operation.    
 
(iv) 
Calculation of RBP Credit Requirement for RBP Sellers Seeking to 
Submit RBP Sell Offers in the RBP  
 
RBP Sell Offers submitted by RBP Sellers in the Reliability Backstop Procurement shall 
be accompanied by a Reliability Backstop Procurement credit requirement, which shall 
be equal to:  
 
 
 
 
(v) 
Credit Responsibility for Traded RBP Resource Commitment 
 
The Office of the Interconnection may require that credit and financial responsibility for 
a committed RBP Resource that is traded remain with the original party (which for these 
purposes, means the party bearing credit responsibility for the committed RBP Resource 
immediately prior to trade) unless the Office of the Interconnection determines that the 
receiving party has independently posted sufficient credit support with the Office of the 
Interconnection and agreed by providing written confirmation to the Office of the 
Interconnection that it will fully assume the credit responsibility associated with the 
committed RBP Resource.  In determining the appropriate level of credit for any 
receiving party, the Office of the Interconnection may rely on Tariff, Attachment Q. 
 
(b) 
RBP Credit Requirements Applicable to Load Serving Entities Responsible for 
RBP Charges  
 
Prior to the first Delivery Year, the assessment of an RBP credit requirement by the Office of the 
Interconnection, LSEs allocated cost responsibility for RBP Charges, pursuant to Tariff, 
Attachment DD, section 18.3, must post RBP Collateral for the RBP credit requirement, 
calculated as set forth herein: 
 
(i) 
RBP Credit Requirement for Load Serving Entities

(A) 
The cumulative RBP credit requirement for Load Serving Entities 
for a given Delivery Year shall be equivalent to the product of the RBP Credit 
Rate multiplied by RBP UCAP MW committed, where  
 
the RBP Credit Rate shall equal $1.5 million, as may be reduced, 
for reasons including a change in the total committed RBP UCAP MW, 
when total posted RBP Collateral is greater than the total remaining RBP 
Charges obligations, over time by the Office of the Interconnection to an 
amount sufficient to cover the total existing RBP Charges obligations; and   
 
the RBP UCAP MW committed amount shall equal the amount of 
RBP UCAP MW that receives a commitment through the Reliability 
Backstop Procurement minus each commitment of RBP UCAP MW that 
is rescinded pursuant to Tariff, Attachment DD, section 18.6(e).   
 
The cumulative RBP credit requirement shall be met through RBP Collateral 
posted by those Load Serving Entities allocated cost pursuant to Tariff, 
Attachment DD, section 18.3. 
 
(B) 
The Office of the Interconnection shall apply the following credit 
requirements to each Load Serving Entity allocated responsibility for RBP 
Obligations, pursuant to Tariff, Attachment DD, section 18.3, as follows: 
 
(1) 
For Load Serving Entities with an RBP Obligation in 
accordance Tariff, Attachment DD, section 18.3, prior to forty-five (45) 
days before the start of the Delivery Year, such Load Serving Entities, 
must post, or maintain an existing, RBP Collateral equal to $1.5 million x 
the allocated RBP Obligation MW, where the RBP Obligation MW equals 
the RBP Obligation MW submitted for the Load Serving Entity by the 
Electric Distributor and scaled, as necessary, in the event that the RBP 
Obligation MW values uploaded by the Electric Distributor do not sum to 
the fixed, Final RBP Target MW for the zone/area.  For Load Serving 
Entities required to post RBP Collateral by the foregoing sentence, the 
Office of the Interconnection may evaluate such Load Serving Entity for 
unreasonable credit risk under the Unreasonable Credit Risk provisions of 
Tariff, Attachment Q, Section II, and require additional RBP Collateral as 
appropriate.   
 
(2) 
To the extent such Load Serving Entity is allocated cost 
pursuant to Tariff, Attachment DD, section 18.3 and no RBP Obligations 
are reported to the Office of the Interconnection in an Electric Distributor 
zone/area in which the Load Serving Entity serves load, prior to forty-five 
(45) days before the start of the Delivery Year, such Load Serving 
Entities, may be required to post, or maintain an existing, RBP Collateral 
equal to the product of the RBP Credit Rate multiplied by the allocated 
RBP UCAP MW, where the allocated RBP UCAP MW shall equal the

Load Serving Entity’s pro-rata share of the Daily Unforced Capacity 
Obligation for the zone/area as determined in RAA, Schedule 8.  For Load 
Serving Entities required to post RBP Collateral by the foregoing 
sentence, the Office of the Interconnection may evaluate whether such 
Load Serving Entity for unreasonable credit risk under the Unreasonable 
Credit Risk provisions of Tariff, Attachment Q, Section II, and require 
additional RBP Collateral as appropriate. 
 
(C) 
Credit Requirements Associated With Intra-Delivery Year Transfer 
of Load and Allocated RBP UCAP MW Cost Responsibility  
 
(1) 
To the extent a Load Serving Entity transfers its load 
serving obligations that are associated with RBP UCAP MW, as 
determined pursuant to Tariff, Attachment DD, section 18.3, then the 
transferee LSE must fully satisfy all applicable credit and collateral 
requirements required herein associated with such transferred RBP UCAP 
MW obligation and, as applicable, the credit requirements in Tariff, 
Attachment Q.  Transferee shall independently post sufficient RBP 
Collateral directly with the Office of the Interconnection to satisfy the 
incremental RBP UCAP MW associated with the acquired load. 
 
(2) 
Transferor shall be released from its financial obligations 
for amount of RBP Collateral associated with the RBP UCAP MW 
associated with the transferred load.  Any RBP Collateral posted by 
transferor shall be returned once Transferee has posted the RBP Collateral 
determined in accordance with Tariff, Attachment DD, section 18.8(c) and 
any unpaid invoice amounts associated with such transfer have been paid 
by the transferor.

18.9 
RBP Default Allocation 
 
(a) 
LSE Nonpayment of RBP Charges 
In the event a Load Serving Entity defaults and fails to pay an RBP Charge, the defaulted amount 
will be allocated to all remaining Load Serving Entities responsible for paying RBP Charges 
based on their pro-rata share of the total RBP Charges for all such Load Serving Entities. Such 
amounts may be offset by the RBP Collateral posted by the defaulting Load Serving Entity. 
 
(b) 
RBP Resource Nonpayment of RBP Shortfall Charges 
 
In the event that an RBP Resource subject to RBP shortfall charges pursuant to Tariff, 
Attachment DD, section 18.6(d) defaults on payment of RBP shortfall charges, the 
corresponding credits will not be allocated to the Load Serving Entities that would otherwise 
receive the RBP shortfall credits.

ARTICLE 1 – DEFINITIONS 
 
 
Unless the context otherwise specifies or requires, capitalized terms used herein shall 
have the respective meanings assigned herein or in the Schedules hereto, or in the PJM Tariff or 
PJM Operating Agreement if not otherwise defined in this Agreement, for all purposes of this 
Agreement (such definitions to be equally applicable to both the singular and the plural forms of 
the terms defined).  Unless otherwise specified, all references herein to Articles, Sections or 
Schedules, are to Articles, Sections or Schedules of this Agreement. As used in this Agreement: 
 
 
Accredited UCAP: 
 
“Accredited UCAP” shall mean the quantity of Unforced Capacity, as denominated in Effective 
UCAP, that an ELCC Resource is capable of providing in a given Delivery Year. 
 
Accredited UCAP Factor: 
 
“Accredited UCAP Factor” shall mean, through the 2024/2025 Delivery Year, one minus 
EFORd, and for 2025/2026 Delivery Year and subsequent Delivery Years, the ratio of the 
Capacity Resource’s Accredited UCAP to the Capacity Resource’s installed capacity. 
 
Agreement: 
 
 
“Agreement” shall mean this Reliability Assurance Agreement, together with all Schedules 
hereto, as amended from time to time. 
 
Annual Demand Resource: 
 
“Annual Demand Resource” shall mean a resource that is placed under the direction of the 
Office of the Interconnection  during the Delivery Year, and will be available for an unlimited 
number of interruptions during such Delivery Year by the Office of the Interconnection, and will 
be capable of maintaining each such interruption between the hours of 10:00AM to 10:00PM 
Eastern Prevailing Time for the months of June through October and the following May, and 
6:00AM through 9:00PM Eastern Prevailing Time for the months of November through April 
unless there is an Office of the Interconnection approved maintenance outage during October 
through April.  The Annual Demand Resource must be available in the corresponding Delivery 
year to be offered for sale or Self-Supplied in an RPM Auction, or included as an Annual 
Demand Resource in an FRR Capacity Plan for the corresponding Delivery Year. 
 
Annual Energy Efficiency Resource: 
 
“Annual Energy Efficiency Resource” shall mean a project, including installation of more 
efficient devices or equipment or implementation of more efficient processes or systems, 
meeting the requirements of  Reliability Assurance Agreement, Schedule 6 and exceeding then-
current building codes, appliance standards, or other relevant standards, designed to achieve a 
continuous (during the summer and winter periods described in such Schedule 6 and the PJM 
Manuals) reduction in electric energy consumption that is not reflected in the peak load forecast

prepared for the Delivery Year for which the Energy Efficiency Resource is proposed, and that is 
fully implemented at all times during such Delivery Year, without any requirement of notice, 
dispatch, or operator intervention. 
 
Applicable Regional Entity: 
 
 
“Applicable Regional Entity” shall have the same meaning as in the PJM Tariff.   
 
Base Capacity Demand Resource: 
 
“Base Capacity Demand Resource” shall mean, for the 2018/2019 and 2019/2020 Delivery 
Years, a resource that is placed under the direction of the Office of the Interconnection and that 
will be available June through September of a Delivery Year, and will be available to the Office 
of the Interconnection for an unlimited number of interruptions during such months, and will be 
capable of maintaining each such interruption for at least a 10-hour duration between the hours 
of 10:00AM to 10:00PM Eastern Prevailing Time.  The Base Capacity Demand Resource must 
be available June through September in the corresponding Delivery Year to be offered for sale or 
self-supplied in an RPM Auction, or included as a Base Capacity Demand Resource in an FRR 
Capacity Plan for the corresponding Delivery Year.   
 
Base Capacity Energy Efficiency Resource:  
 
“Base Capacity Energy Efficiency Resource” shall mean, for the 2018/2019 and 2019/2020 
Delivery Years, a project, including installation of more efficient devices or equipment or 
implementation of more efficient processes or systems, meeting the requirements of RAA, 
Schedule 6 and exceeding then-current building codes, appliance standards, or other relevant 
standards, designed to achieve a continuous (during the summer peak periods as described in 
Reliability Assurance Agreement, Schedule 6 and the PJM Manuals) reduction in electric energy 
consumption that is not reflected in the peak load forecast prepared for the Delivery Year for 
which the Base Capacity Energy Efficiency Resource is proposed, and that is fully implemented 
at all times during such Delivery Year, without any requirement of notice, dispatch, or operator 
intervention. 
 
Base Capacity Resource:  
 
“Base Capacity Resource” shall have the same meaning as in Tariff, Attachment DD. 
 
Base Residual Auction: 
 
 
“Base Residual Auction” shall have the same meaning as in Tariff, Attachment DD. 
 
 
Behind The Meter Generation: 
 
 
“Behind The Meter Generation” shall refer to a generating unit that delivers energy to load 
without using the Transmission System or any distribution facilities (unless the entity that owns 
or leases the distribution facilities consented to such use of the distribution facilities and such

consent has been demonstrated to the satisfaction of the Office of the Interconnection; provided, 
however, that Behind The Meter Generation does not include (i) at any time, any portion of such 
generating unit’s capacity that is designated as a Generation Capacity Resource or DER Capacity 
Aggregation Resource or (ii) in any hour, any portion of the output of such generating unit that is 
sold to another entity for consumption at another electrical location or into the PJM Interchange 
Energy Market. 
 
 
Black Start Capability: 
 
 
“Black Start Capability” shall mean the ability of a generating unit or station to go from a 
shutdown condition to an operating condition and start delivering power without assistance from 
the power system. 
 
 
Capacity Emergency Transfer Objective (CETO): 
 
 
“Capacity Emergency Transfer Objective” or “CETO” shall mean, through the 2024/2025 
Delivery Year, the amount of electric energy that a given area must be able to import in order to 
remain within a loss of load expectation of one event in 25 years when the area is experiencing a 
localized capacity emergency, as determined in accordance with the PJM Manuals.  Without 
limiting the foregoing, CETO shall be, for Delivery Years through 2024/2025, calculated based 
in part on EFORD determined in accordance with Reliability Assurance Agreement, Schedule 5, 
Paragraph C. Beginning with the 2025/2026 Delivery Year, CETO shall mean the amount of 
electric energy that a given area must be able to import in order to satisfy a normalized expected 
unserved energy for the area that is equal to forty percent of the normalized expected unserved 
energy for the RTO when at the annual reliability criteria, where normalized expected unserved 
energy is the expected unserved energy (for the area or RTO, as appropriate) divided by  the 
forecasted annual energy (for the area or RTO, as appropriate), when the area is experiencing a 
localized capacity emergency, as determined in accordance with the PJM Manuals. 
 
 
Capacity Emergency Transfer Limit (CETL): 
 
 
Capacity Emergency Transfer Limit” or “CETL” shall mean the capability of the transmission 
system to support deliveries of electric energy to a given area experiencing a localized capacity 
emergency as determined in accordance with the PJM Manuals. 
 
 
Capacity Import Limit: 
 
For any Delivery Year up to and including the 2019/2020 Delivery Year, “Capacity Import 
Limit” shall mean, (a) for the PJM Region, (1) the maximum megawatt quantity of external 
Generation Capacity Resources that PJM determines for each Delivery Year, through appropriate 
modeling and the application of engineering judgment, the transmission system can receive, in 
aggregate at the interface of the PJM Region with all external balancing authority areas and 
deliver to load in the PJM Region under capacity emergency conditions without violating 
applicable reliability criteria on any bulk electric system facility of 100kV or greater, internal or 
external to the PJM Region, that has an electrically significant response to transfers on such 
interface, minus (2) the then-applicable Capacity Benefit Margin; and (b) for certain source

zones identified in the PJM manuals as groupings of one or more balancing authority areas, (1) 
the maximum megawatt quantity of external Generation Capacity Resources that PJM 
determines the transmission system can receive at the interface of the PJM Region with each 
such source zone and deliver to load in the PJM Region under capacity emergency conditions 
without violating applicable reliability criteria on any bulk electric system facility of 100kV or 
greater, internal or external to the PJM Region, that has an electrically significant response to 
transfers on such interface, minus the then-applicable Capacity Benefit Margin times (2) the ratio 
of the maximum import quantity from each such source zone divided by the PJM total maximum 
import quantity.  As more fully set forth in the PJM Manuals, PJM shall make such 
determination based on the latest peak load forecast for the studied period, the same computer 
simulation model of loads, generation and transmission topography employed in the 
determination of Capacity Emergency Transfer Limit for such Delivery Year, including external 
facilities from an industry standard model of the loads, generation, and transmission topography 
of the Eastern Interconnection under peak conditions.  PJM shall specify in the PJM Manuals the 
areas and minimum distribution factors for identifying monitored bulk electric system facilities 
that have an electrically significant response to such transfers on the PJM interface.  Employing 
such tools, PJM shall model increased power transfers from external areas into PJM to determine 
the transfer level at which one or more reliability criteria is violated on any monitored bulk 
electric system facilities that have an electrically significant response to such transfers.  For the 
PJM Region Capacity Import Limit, PJM shall optimize transfers from other source areas not 
experiencing any reliability criteria violations as appropriate to increase the Capacity Import 
Limit.  The aggregate megawatt quantity of transfers into PJM at the point where any increase in 
transfers on the interface would violate reliability criteria will establish the Capacity Import 
Limit.  Notwithstanding the foregoing, a Capacity Resource located outside the PJM Region 
shall not be subject to the Capacity Import Limit if the Capacity Market Seller seeks an 
exception thereto by demonstrating to PJM, by no later than five (5) business days prior to the 
commencement of the offer period for the relevant RPM Auction, that such resource meets all of 
the following requirements: 
(i)  
it has, at the time such exception is requested, met all applicable requirements to 
be pseudo-tied into the PJM Region, or the Capacity Market Seller has committed in writing that 
it will meet such requirements, unless prevented from doing so by circumstances beyond the 
control of the Capacity Market Seller, prior to the relevant Delivery Year; 
 
(ii)  
at the time such exception is requested, it has long-term firm transmission service 
confirmed on the complete transmission path from such resource into PJM; and 
 
(iii) 
it is, by written commitment of the Capacity Market Seller, subject to the same 
obligations imposed on Generation Capacity Resources located in the PJM Region by Tariff, 
Attachment DD, section 6.6 to offer their capacity into RPM Auctions; provided, however, that 
(a) the total megawatt quantity of all exceptions granted hereunder for a Delivery Year, plus the 
Capacity Import Limit for the applicable interface determined for such Delivery Year, may not 
exceed the total megawatt quantity of Network External Designated Transmission Service on 
such interface that PJM has confirmed for such Delivery Year; and (b) if granting a qualified 
exception would result in a violation of the rule in clause (a), PJM shall grant the requested 
exception but reduce the Capacity Import Limit by the quantity necessary to ensure that the total 
quantity of Network External Designated Transmission Service is not exceeded.

Capacity Only Option: 
 
“Capacity Only Option” shall mean participation in Emergency Load Response Program or Pre-
Emergency Program which allows, pursuant to Tariff, Attachment DD and as applicable, a 
capacity payment for the ability to reduce load during a pre-emergency or emergency event. 
 
Capacity Performance Resource: 
 
“Capacity Performance Resource” shall have the same meaning as in Tariff, Attachment DD. 
 
Capacity Resources: 
 
 
“Capacity Resources” shall mean megawatts of (i) net capacity from Existing Generation 
Capacity Resources or Planned Generation Capacity Resources meeting the requirements of the 
Reliability Assurance Agreement, Schedules 9 and Reliability Assurance Agreement, Schedule 
10 that are or will be owned by or contracted to a Party and that are or will be committed to 
satisfy that Party's obligations under the Reliability Assurance Agreement, or to satisfy the 
reliability requirements of the PJM Region, for a Delivery Year; (ii) net capacity from Existing 
Generation Capacity Resources or Planned Generation Capacity Resources not owned or 
contracted for by a Party which are accredited to the PJM Region pursuant to the procedures set 
forth in such Schedules 9 and 10; or (iii)  load reduction capability provided by Demand 
Resources or Energy Efficiency Resources that are accredited to the PJM Region pursuant to the 
procedures set forth in the Reliability Assurance Agreement, Schedule 6; or (iv) generation and 
load reduction capability provided by a DER Capacity Aggregation Resource, pursuant to the 
procedures set forth in the Reliability Assurance Agreement, Schedule 6.2 and the PJM Manuals. 
 
 
Capacity Resource Provider: 
 
“Capacity Resource Provider” shall mean a Member that (1) owns, or has the contractual 
authority to control the output of, a Generation Capacity Resource, that has not transferred such 
authority to another entity; (2) or a DER Aggregator that has a contractual relationship to use a 
Component DER within a DER Aggregation Resource that is linked to a DER Capacity 
Aggregation Resource. 
 
Capacity Storage Resource Class: 
 
“Capacity Storage Resource Class” shall mean the ELCC Classes specified in Schedules 9.1 and 
9.2, section B of this Agreement, each of which is composed of (1) Capacity Storage Resources 
with the same specified characteristic duration of 4, 6, 8, and 10 hours or; (2) storage device 
Component DER. The characteristic duration of an Energy Storage Resource Class is the ratio of 
the modeled MWh energy storage capability of members of the class to the modeled MW power 
capability of members of the class. 
 
Capacity Transfer Right:

“Capacity Transfer Right” shall have the meaning specified in Tariff, Attachment DD. 
 
Coal Class: 
 
 
“Coal Class” shall mean an ELCC Class consisting of Unlimited Resources primarily 
fueled by coal. 
 
Combination Resource: 
 
“Combination Resource” shall mean a Generation Capacity Resource, or a generation 
Component DER within a DER Aggregation Resource that is linked to a DER Capacity 
Aggregation Resource, that has a component that has the characteristics of a Limited Duration 
Resource combined with (i) a component that has the characteristics of an Unlimited Resource or 
(ii) a component that has the characteristics of a Variable Resource. 
 
Compliance Aggregation Area (CAA): 
 
“Compliance Aggregation Area” or “CAA” shall have the same meaning as in the Tariff. 
 
Complex Hybrid Class: 
 
“Complex Hybrid Class” shall mean an ELCC Class composed of Combination Resources that 
combine three or more components, whereby one component is a class of Limited Duration 
Resource, and the other components are different Variable Resource classes, and such 
Combination Resources cannot be included in any other Combination Resource class. A resource 
that is a member of a Complex Hybrid Class has a single Point Of Interconnection, unless the 
resource is controlled in an integrated fashion, is at a single site, and is approved by PJM to be 
considered a single resource in accordance with the PJM Manuals. 
 
Consolidated Transmission Owners Agreement, PJM Transmission Owners Agreement or 
Transmission Owners Agreement: 
 
 
“Consolidated Transmission Owners Agreement,” “PJM Transmission Owners Agreement” or 
“Transmission Owners Agreement” shall mean that certain Consolidated Transmission Owners 
Agreement, dated as of December 15, 2005, by and among the Transmission Owners and by and 
between the Transmission Owners and PJM Interconnection, L.L.C. on file with the 
Commission, as amended from time to time. 
 
 
Control Area: 
 
“Control Area” shall mean an electric power system or combination of electric power systems 
bounded by interconnection metering and telemetry to which a common generation control 
scheme is applied in order to:

(a) 
match the power output of the generators within the electric power system(s) and 
energy purchased from entities outside the electric power system(s), with the load within the 
electric power system(s); 
 
 
 
(b) 
maintain scheduled interchange with other Control Areas, within the limits of 
Good Utility Practice; 
 
 
 
 (c) 
maintain the frequency of the electric power system(s) within reasonable limits in 
accordance with Good Utility Practice and the criteria of NERC and each Applicable Regional 
Entity; 
 
 
 
(d) 
maintain power flows on transmission facilities within appropriate limits to 
preserve reliability; and 
 
 
 
(e) 
provide sufficient generating capacity to maintain operating reserves in 
accordance with Good Utility Practice. 
 
 
Daily Unforced Capacity Obligation: 
 
 
“Daily Unforced Capacity Obligation” shall mean the capacity obligation of a Load Serving 
Entity during the Delivery Year, determined in accordance with the Reliability Assurance 
Agreement, Schedule 8 or, as to an FRR Entity, in the Reliability Assurance Agreement, 
Schedule 8.1. 
 
 
Delivery Year: 
 
 
“Delivery Year” shall mean a Planning Period for which a Capacity Resource is committed 
pursuant to the auction procedures specified in Tariff, Attachment DD or pursuant to an FRR 
Capacity Plan under RAA, Schedule 8.1. 
 
 
Demand Resource (DR): 
 
 
“Demand Resource” or “DR” shall mean a Limited Demand Resource, Extended Summer 
Demand Resource, Annual Demand Resource, Base Capacity Demand Resource or Summer-
Period Demand Resource with a demonstrated capability to provide a reduction in demand or 
otherwise control load in accordance with the requirements of RAA, Schedule 6 that offers and 
that clears load reduction capability in a Base Residual Auction or Incremental Auction or that is 
committed through an FRR Capacity Plan.   
 
Demand Resource Factor or DR Factor: 
 
 
“Demand Resource Factor” or “DR Factor” shall mean, for Delivery Years through May 31, 
2018, that factor approved from time to time by the PJM Board used to determine the unforced 
capacity value of a Demand Resource in accordance with Reliability Assurance Agreement, 
Schedule 6

Demand Resource Officer Certification Form: 
 
“Demand Resource Officer Certification Form” shall mean a certification as to an intended 
Demand Resource Sell Offer, in accordance with Reliability Assurance Agreement, Schedule 6 
and Reliability Assurance Agreement, Schedule 8.1 and the PJM Manuals. 
 
 
Demand Resource Registration: 
 
“Demand Resource Registration” shall mean a registration in the Full Program Option or 
Capacity Only Option of the Emergency or Pre-Emergency Load Resource Program in 
accordance with Tariff, Attachment K-Appendix, section 8. 
 
Demand Resource Sell Offer Plan: 
 
“Demand Resource Sell Offer Plan” shall mean the plan required by Reliability Assurance 
Agreement, Schedule 6 and Reliability Assurance Agreement, Schedule 8.1 in support of an 
intended offer of Demand Resources in an RPM Auction, or an intended inclusion of Demand 
Resources in an FRR Capacity Plan. 
 
Diesel Utility Class: 
 
"Diesel Utility Class" shall mean an ELCC Class consisting of Unlimited Resources of the diesel 
technology type that is not primarily fueled by landfill gas. 
 
DER Aggregator Officer Certification Form:  
 
“DER Aggregator Officer Certification Form” shall mean a DER Aggregator’s certification as to 
an intended DER Capacity Aggregation Resource Sell Offer, in accordance with Reliability 
Assurance Agreement, Schedule 6.2 and Reliability Assurance Agreement, Schedule 8.1 and the 
PJM Manuals. 
 
DER Capacity Aggregation Resource Sell Offer Plan:  
 
“DER Capacity Aggregation Resource Sell Offer Plan” shall mean the plan required by 
Reliability Assurance Agreement, Schedule 6.2 and Reliability Assurance Agreement, Schedule 
8.1 in support of an intended offer of a DER Capacity Aggregation Resource in an RPM 
Auction, or an intended inclusion of a DER Capacity Aggregation Resource in an FRR Capacity 
Plan. 
 
Effective Nameplate Capacity: 
 
“Effective Nameplate Capacity” shall mean (i) for each Variable Resource and Combination 
Resource that is a Generation Capacity Resource, the resource’s Maximum Facility Output (or, 
for a Co-Located Resource, the applicable share of the Mixed Technology Facility’s Maximum 
Facility Output); (ii) for each Variable Resource and Combination Resource, that is an individual 
Component DER within a DER Aggregation Resource that is linked to a DER Capacity

Aggregation Resource, the device’s maximum energy production capability, as defined by the 
resource’s state interconnection agreement; or (iii) for each Limited Duration Resource, the 
sustained level of output that the device can provide and maintain over a continuous period, 
whereby the duration of that continuous period matches the characteristic duration of the 
corresponding ELCC Class, with consideration given to ambient conditions expected to exist at 
the time of PJM system peak load, to the extent that such conditions impact such resource’s 
capability, not to exceed the Maximum Facility Output (or, for a Co-Located Resource, the 
applicable share of the Mixed Technology Facility’s Maximum Facility Output).  For the 
2025/2026 Delivery Year and subsequent Delivery Years, the Effective Nameplate Capacity of 
each Limited Duration Resource shall not exceed the greater of the Capacity Interconnection 
Rights of such Limited Duration Resource, or the transitional system capability as limited by the 
transitional resource MW ceiling as defined in the PJM Manuals, awarded for the applicable 
Delivery Year. 
 
Effective UCAP: 
 
“Effective UCAP” shall mean a unit of measure that represents the capacity product transacted in 
the Reliability Pricing Model and included in FRR Capacity Plans.  One megawatt of Effective 
UCAP has the same capacity value of one megawatt of Unforced Capacity. 
 
ELCC Class: 
 
“ELCC Class” shall mean a defined group of ELCC Resources that share a common set of 
operational characteristics and for which effective load carrying capability analysis, as set forth 
in RAA, Schedules 9.1 and 9.2, will establish a unique ELCC Class UCAP and corresponding 
ELCC Class Rating(s). ELCC Classes shall be defined in the Schedules 9.1 and 9.2, section B of 
this Agreement.  Members of an ELCC Class shall share a common method of calculating the 
ELCC Resource Performance Adjustment, provided that the individual ELCC Resource 
Performance Adjustment values will generally differ among ELCC Resources. 
 
ELCC Class Rating: 
 
“ELCC Class Rating” shall mean the rating factor, based on effective load carrying capability 
analysis, that applies to ELCC Resources that are members of an ELCC Class as part of the 
calculation of their Accredited UCAP. 
 
ELCC Class UCAP: 
 
“ELCC Class UCAP” shall mean the aggregate Effective UCAP all modeled ELCC Resources in 
a given ELCC Class are capable of providing in a given Delivery Year.  
 
ELCC Portfolio UCAP: 
 
“ELCC Portfolio UCAP” shall mean the aggregate Effective UCAP that all modeled ELCC 
Resources are capable of providing in a given Delivery Year.

ELCC Resource: 
 
“ELCC Resource” shall mean a Component DER within a DER Aggregation Resource that is 
linked to a DER Capacity Aggregation Resource, a Generation Capacity Resource or a Demand 
Resource. 
 
ELCC Resource Performance Adjustment: 
 
“ELCC Resource Performance Adjustment” shall mean the performance of a specific ELCC 
Resource relative to the aggregate performance of the ELCC Class to which it belongs as further 
described in RAA, Schedule 9.1, section F and RAA, Schedule 9.2, section D. 
 
Electric Cooperative: 
 
 
“Electric Cooperative” shall mean an entity owned in cooperative form by its customers that is 
engaged in the generation, transmission, and/or distribution of electric energy. 
 
 
Electric Distributor: 
 
 
“Electric Distributor” shall mean a Member that 1) owns or leases with rights equivalent to 
ownership of electric distribution facilities that are used to provide electric distribution service to 
electric load within the PJM Region; or 2) is a generation and transmission cooperative or a joint 
municipal agency that has a member that owns electric distribution facilities used to provide 
electric distribution service to electric load within the PJM Region. 
 
 
Emergency: 
 
 
“Emergency” shall mean (i) an abnormal system condition requiring manual or automatic action 
to maintain system frequency, or to prevent loss of firm load, equipment damage, or tripping of 
system elements that could adversely affect the reliability of an electric system or the safety of 
persons or property; or (ii) a fuel shortage requiring departure from normal operating procedures 
in order to minimize the use of such scarce fuel; or (iii) a condition that requires implementation 
of emergency procedures as defined in the PJM Manuals. 
 
 
End-Use Customer: 
 
 
“End-Use Customer” shall mean a Member that is a retail end-user of electricity within the PJM 
Region.  For purposes of Members Committee sector classification, a Member that is a retail 
end-user that owns generation may qualify as an End-Use customer if:  (1) the average physical 
unforced capacity owned by the Member and its affiliates in the PJM region over the five 
Planning Periods immediately preceding the relevant Planning Period does not exceed the 
average PJM capacity obligation for the Member and its affiliates over the same time period; or 
(2) the average energy produced by the Member and its affiliates within the PJM region over the 
five Planning Periods immediately preceding the relevant Planning Period does not exceed the 
average energy consumed by that Member and its affiliates within the PJM region over the same

time period.  The foregoing notwithstanding, taking retail service may not be sufficient to qualify 
a Member as an End-Use Customer. 
 
 
 
Energy Efficiency Resource: 
 
 
“Energy Efficiency Resource” shall mean a project, including installation of more efficient 
devices or equipment or implementation of more efficient processes or systems, meeting the 
requirements of RAA, Schedule 6 and exceeding then-current building codes, appliance 
standards, or other relevant standards, designed to achieve a continuous (during the periods 
described in Reliability Assurance Agreement, Schedule 6 and the PJM Manuals) reduction in 
electric energy consumption that is not reflected in the peak load forecast prepared for the 
Delivery Year for which the Energy Efficiency Resource is proposed, and that is fully 
implemented at all times during such Delivery Year, without any requirement of notice, dispatch, 
or operator intervention.  Annual Energy Efficiency Resources, Base Capacity Energy Efficiency 
Resources and Summer-Period Energy Efficiency Resources are types of Energy Efficiency 
Resources. 
 
Exigent Water Storage: 
 
“Exigent Water Storage” shall mean water stored in the pondage or reservoir of a hydropower 
resource which is not typically available during normal operating conditions (as those conditions 
are described in the relevant FERC hydropower license), but which can be drawn upon during 
emergency conditions (as described in the FERC hydropower license), including in order to 
avoid a load shed.  In an effective load carrying capability analysis, exigent storage capability 
from an upstream hydro facility can be considered relative to a downstream hydro facility by 
assessing cascading storage and flows. 
 
Existing Demand Resource: 
 
“Existing Demand Resource” shall mean a Demand Resource for which the Demand Resource 
Provider has identified existing end-use customer sites that are registered for the current Delivery 
Year with PJM (even if not registered by such Demand Resource Provider) and that the Demand 
Resource Provider reasonably expects to have under a contract to reduce load based on PJM 
dispatch instructions by the start of the Delivery Year for which such resource is offered. 
 
Existing DER Capacity Aggregation Resource: 
 
“Existing DER Capacity Aggregation Resource” shall mean a DER Capacity Aggregation 
Resource for which the DER Aggregator has identified existing Component DER that are 
registered in a DER Capacity Aggregation Resource for the current Delivery Year with PJM 
(even if not registered by such DER Aggregator) and that the DER Aggregator reasonably 
expects to have under a contract to generate or reduce load based on PJM dispatch instructions 
by the start of the Delivery Year for which such DER Capacity Aggregation Resource is offered. 
 
Existing Generation Capacity Resource:

“Existing Generation Capacity Resource” shall mean, for purposes of the must-offer requirement 
and mitigation of offers for any RPM Auction for a Delivery Year, a Generation Capacity 
Resource that, as of the date on which bidding commences for such auction: (a) is in service; or 
(b) is not yet in service, but has cleared any RPM Auction for any prior Delivery Year.  A 
Generation Capacity Resource shall be deemed to be in service if interconnection service has 
ever commenced (for resources located in the PJM Region), or if it is physically and electrically 
interconnected to an external Control Area and is in full commercial operation (for resources not 
located in the PJM Region).  The additional megawatts of a Generation Capacity Resource that is 
being, or has been, modified to increase the number of megawatts of available installed capacity 
thereof shall not be deemed to be an Existing Generation Capacity Resource until such time as 
those megawatts (a) are in service; or (b) are not yet in service, but have cleared any RPM 
Auction for any prior Delivery Year. 
 
Extended Summer Demand Resource: 
 
“Extended Summer Demand Resource” shall mean, for Delivery Years through May 31, 2018, 
and for FRR Capacity Plans Delivery Years through May 31, 2019, a resource that is placed 
under the direction of the Office of the Interconnection and that will be available June through 
October and the following May, and will be available for an unlimited number of interruptions 
during such months by the Office of the Interconnection, and will be capable of maintaining each 
such interruption for at least a 10-hour duration between the hours of 10:00AM to 10:00PM 
Eastern Prevailing Time. The Extended Summer Demand Resource must be available June 
through October and the following May in the corresponding Delivery Year to be offered for sale 
or Self-Supplied in an RPM Auction, or included as an Extended Summer Demand Resource in 
an FRR Capacity Plan for the corresponding Delivery Year.   
 
 
Facilities Study Agreement: 
 
 
“Facilities Study Agreement” shall have the same meaning as in Tariff, Part VI, section 206. 
 
 
 
FERC or Commission: 
 
 
“FERC” or “Commission” shall mean the Federal Energy Regulatory Commission or any 
successor federal agency, commission or department exercising jurisdiction over the Tariff, 
Operating Agreement and Reliability Assurance Agreement. 
 
 
Firm Point-To-Point Transmission Service: 
 
 
“Firm Point-To-Point Transmission Service” shall have the meaning specified in the Tariff. 
 
 
Firm Service Level: 
 
“Firm Service Level” or “FSL” of Price Responsive Demand shall mean the level, determined at 
a PRD Substation level, to which Price Responsive Demand shall be reduced during the Delivery 
Year when the Locational Marginal Price exceeds the price associated with such Price

Responsive Demand identified by the PRD Provider in its PRD Plan. “Firm Service Level” or 
“FSL” of Demand Resource shall mean the pre-determined level to which an end-use customer’s 
load shall be reduced, upon notification from the Curtailment Service Provider’s market 
operations center or its agent. 
 
Firm Transmission Service: 
 
 
“Firm Transmission Service” shall mean transmission service that is intended to be available at 
all times to the maximum extent practicable, subject to an Emergency, an unanticipated failure of 
a facility, or other event beyond the control of the owner or operator of the facility or the Office 
of the Interconnection. 
 
 
Fixed Resource Requirement Alternative or FRR Alternative: 
 
 
“Fixed Resource Requirement Alternative” or “FRR Alternative” shall mean an alternative 
method for a Party to satisfy its obligation to provide Unforced Capacity hereunder, as set forth 
in the Reliability Assurance Agreement, Schedule 8.1. 
 
Fixed-Tilt Solar Class: 
 
“Fixed-Tilt Solar Class” shall mean an ELCC Class consisting of Variable Resources that 
produce electrical energy with solar panels that are primarily mounted in a fixed orientation. 
 
 
Forecast Pool Requirement: 
 
 
“Forecast Pool Requirement” or “FPR” shall mean the amount equal to one plus the unforced 
reserve margin (stated as a decimal number) for the PJM Region required pursuant to this 
Reliability Assurance Agreement, as approved by the PJM Board pursuant to Reliability 
Assurance Agreement, Schedule 4.1. 
 
 
FRR Capacity Plan or FRR Plan: 
 
 
“FRR Capacity Plan” or “FRR Plan” shall mean a long-term plan for the commitment of 
Capacity Resources and Price Responsive Demand to satisfy the capacity obligations of a Party 
that has elected the FRR Alternative, as more fully set forth in the Reliability Assurance 
Agreement, Schedule 8.1. 
 
 
FRR Entity: 
 
 
“FRR Entity” shall mean, for the duration of such election, a Party that has elected the FRR 
Alternative hereunder. 
 
 
FRR Service Area: 
 
 
“FRR Service Area” shall mean (a) the service territory of an IOU as recognized by state law, 
rule or order; (b) the service area of a Public Power Entity or Electric Cooperative as recognized

by franchise or other state law, rule, or order; or (c) a separately identifiable geographic area that 
is: (i) bounded by wholesale metering, or similar appropriate multi-site aggregate metering, that 
is visible to, and regularly reported to, the Office of the Interconnection, or that is visible to, and 
regularly reported to an Electric Distributor and such Electric Distributor agrees to aggregate the 
load data from such meters for such FRR Service Area and regularly report such aggregated 
information, by FRR Service Area, to the Office of the Interconnection; and (ii) for which the 
FRR Entity has or assumes the obligation to provide capacity for all load (including load growth) 
within such area.  In the event that the service obligations of an Electric Cooperative or Public 
Power Entity are not defined by geographic boundaries but by physical connections to a defined 
set of customers, the FRR Service Area in such circumstances shall be defined as all customers 
physically connected to transmission or distribution facilities of such Electric Cooperative or 
Public Power Entity within an area bounded by appropriate wholesale aggregate metering as 
described above.   
 
 
Full Program Option: 
 
“Full Program Option” shall mean participation in Emergency Load Response Program or Pre-
Emergency Program which allows, pursuant to Tariff, Attachment DD and as applicable, (i) an 
energy payment for load reductions during a pre-emergency or emergency event, and (ii) a 
capacity payment for the ability to reduce load during a pre-emergency or emergency event. 
 
Full Requirements Service: 
 
 
“Full Requirements Service” shall mean wholesale service to supply all of the power needs of a 
Load Serving Entity to serve end-users within the PJM Region that are not satisfied by its own 
generating facilities. 
 
Gas Combined Cycle Class: 
 
“Gas Combined Cycle Class” shall mean an ELCC Class consisting of Unlimited Resources of 
the combined cycle technology type that is primarily fueled by natural gas, but does not meet the 
requirements to be included in the Gas Combined Cycle Dual Fuel Class. 
 
Gas Combined Cycle Dual Fuel Class: 
 
“Gas Combined Cycle Dual Fuel Class” shall mean an ELCC Class consisting of Unlimited 
Resources of the combined cycle technology type that is primarily fueled by natural gas, and that 
attests that it has the capability to start independently using onsite sources and operate 
independently on alternate onsite fuel source(s) up to its maximum capacity level during the 
winter season of the applicable Delivery Year in which it is providing capacity, and capable of 
operating on the alternate fuel for two 16-hour periods over two consecutive days at its 
maximum capacity level.  
 
Gas Combustion Turbine Class:

“Gas Combustion Turbine Class” shall mean an ELCC Class consisting of Unlimited Resources 
of the combustion turbine technology type that is primarily fueled by natural gas, but does not 
meet the requirements to be included in the Gas Combustion Turbine Dual Fuel Class. 
 
Gas Combustion Turbine Dual Fuel Class: 
 
“Gas Combustion Turbine Dual Fuel Class” shall mean an ELCC Class consisting of Unlimited 
Resources of the combustion turbine technology type that is primarily fueled by natural gas, and 
attests that it has the capability to start independently using onsite sources and operate 
independently on alternate onsite fuel source(s) up to its maximum capacity level during the 
winter season of the applicable Delivery Year in which it is providing capacity, and capable of 
operating on the alternate fuel for two 16-hour periods over two consecutive days at its 
maximum capacity level. 
 
 
Generation Capacity Resource: 
 
 
“Generation Capacity Resource” shall mean a Generating Facility, or the contractual right to 
capacity from a specified Generating Facility, that meets the requirements of RAA, Schedule 9 
and RAA, Schedule 10, and, for Generating Facilities that are committed to an FRR Capacity 
Plan, that meets the requirements of RAA, Schedule 8.1.  A Generation Capacity Resource may 
be an Existing Generation Capacity Resource or a Planned Generation Capacity Resource.  
 
Generation Owner: 
 
 
“Generation Owner” shall mean a Member that owns or leases with rights equivalent to 
ownership, or otherwise controls and operates one or more operating generation resources 
located in the PJM Region.  The foregoing notwithstanding, for a planned generation resource to 
qualify a Member as a Generation Owner, such resource shall have cleared an RPM auction, and 
for Energy Resources, the resource shall have a FERC-jurisdictional interconnection agreement 
or wholesale market participation agreement within PJM.   Purchasing all or a portion of the 
output of a generation resource shall not be sufficient to qualify a Member as a Generation 
Owner.  For purposes of Members Committee sector classification, a Member that is primarily a 
retail end-user of electricity that owns generation may qualify as a Generation Owner if:  (1) the 
generation resource is the subject of a FERC-jurisdictional interconnection agreement or 
wholesale market participation agreement within PJM; (2) the average physical unforced 
capacity owned by the Member and its affiliates over the five Planning Periods immediately 
preceding the relevant Planning Period exceeds the average PJM capacity obligation of the 
Member and its affiliates over the same time period; and (3) the average energy produced by the 
Member and its affiliates within PJM over the five Planning Periods immediately preceding the 
relevant Planning Period exceeds the average energy consumed by the Member and its affiliates 
within PJM over the same time period. 
 
 
Generator Forced Outage: 
 
 
“Generator Forced Outage” shall mean an immediate reduction in output or capacity or removal 
from service, in whole or in part, of a generating unit by reason of an Emergency or threatened

Emergency, unanticipated failure, or other cause beyond the control of the owner or operator of 
the facility, as specified in the relevant portions of the PJM Manuals.  A reduction in output or 
removal from service of a generating unit in response to changes in market conditions shall not 
constitute a Generator Forced Outage. 
 
 
Generator Maintenance Outage: 
 
 
“Generator Maintenance Outage” shall mean the scheduled removal from service, in whole or in 
part, of a generating unit in order to perform repairs on specific components of the facility, if 
removal of the facility qualifies as a maintenance outage pursuant to the PJM Manuals. 
 
 
Generator Planned Outage: 
 
 
“Generator Planned Outage” shall mean the scheduled removal from service, in whole or in part, 
of a generating unit for inspection, maintenance or repair with the approval of the Office of the 
Interconnection in accordance with the PJM Manuals. 
 
 
Good Utility Practice: 
 
 
“Good Utility Practice” shall mean any of the practices, methods and acts engaged in or 
approved by a significant portion of the electric utility industry during the relevant time period, 
or any of the practices, methods and acts which, in the exercise of reasonable judgment in light 
of the facts known at the time the decision was made, could have been expected to accomplish 
the desired result at a reasonable cost consistent with good business practices, reliability, safety 
and expedition.  Good Utility Practice is not intended to be limited to the optimum practice, 
method, or act to the exclusion of all others, but rather is intended to include acceptable 
practices, methods, or acts generally accepted in the region; including those practices required by 
Federal Power Act Section 215(a)(4).  
 
 
Hybrid Resource Class: 
 
“Hybrid Resource Class” shall mean the ELCC Classes specified in RAA Schedules 9.1 and 9.2 
Section B.  Each Hybrid Resource Class has a specified combination of two components, 
whereby, absent being part of a Combination Resource, the individual components would be in a 
Capacity Storage Resource Class, a Variable Resource Class or would be an Unlimited 
Resource.  A resource that is a member of a Hybrid Resource Class has a single Point Of 
Interconnection, unless the resource is controlled in an integrated fashion, is at a single site, and 
is approved by PJM to be considered a single resource in accordance with the PJM Manuals. 
 
Hydropower With Non-Pumped Storage: 
 
“Hydropower With Non-Pumped Storage” shall mean a hydropower facility that can capture and 
store incoming stream flow, without use of pumps, in pondage or a reservoir, and the Generation 
Owner has the ability, within the constraints available in the applicable operating license, to exert 
material control over the quantity of stored water and output of the facility throughout an 
Operating Day.

Hydropower With Non-Pumped Storage Class: 
 
“Hydropower With Non-Pumped Storage Class” shall mean an ELCC Class consisting of 
Combination Resources that are Hydropower With Non-Pumped Storage resources. 
 
Incremental Auction: 
 
 
“Incremental Auction” shall mean any of several auctions conducted for a Delivery Year after 
the Base Residual Auction for such Delivery Year and before the first day of such Delivery Year, 
including the First Incremental Auction, Second Incremental Auction, Third Incremental 
Auction, or Conditional Incremental Auction.  Incremental Auctions (other than the Conditional 
Incremental Auction), shall be held for the purposes of: 
 
(i) 
allowing Market Sellers that committed Capacity Resources in the Base Residual 
Auction for a Delivery Year, which subsequently are determined to be unavailable 
to deliver the committed Unforced Capacity in such Delivery Year (due to 
resource retirement, resource cancellation or construction delay, resource 
derating, EFORd increase, Accredited UCAP Factor decrease, a decrease in the 
Nominated Demand Resource Value of a Planned Demand Resource, delay or 
cancellation of a Qualifying Transmission Upgrade, or similar occurrences) to 
submit Buy Bids for replacement Capacity Resources; and  
 
(ii) 
allowing the Office of the Interconnection to reduce or increase the amount of 
committed capacity secured in prior auctions for such Delivery Year if, as a result 
of changed circumstances or expectations since the prior auction(s), there is, 
respectively, a significant excess or significant deficit of committed capacity for 
such Delivery Year, for the PJM Region or for an LDA. 
 
 
Intermittent Hydropower Class: 
 
“Intermittent Hydropower Class” shall mean an ELCC Class consisting of Variable Resources 
that are run-of-river hydropower generators that must generally pass incoming water and 
therefore cannot appreciably store water to later increase the output of the facility. Resources in 
the Intermittent Hydropower Class are not Hydropower with Non-Pumped Storage resources. 
 
IOU: 
 
 
“IOU” shall mean an investor-owned utility with substantial business interest in owning and/or 
operating electric facilities in any two or more of the following three asset categories:  
generation, transmission, distribution. 
 
Intermittent Landfill Gas Class:

“Intermittent Landfill Gas Class” shall mean an ELCC Class consisting of Variable Resources 
fueled by landfill gas that, because of fuel availability patterns, cannot run consistently at 
installed capacity levels for 24 or more hours. 
 
Large Load Adjustment: 
 
“Large Load Adjustment” shall mean any MW quantity of adjustments to summer peak load at 
the “zone/area” level and summed by Zone as further detailed in PJM Manuals.  For purposes of 
this definition, a “zone/area” is an area within a Zone for which the relevant Electric Distributor 
specifies a separate Obligation Peak Load MW value.  A zone/area is a service area of an 
Electric Distributor that is a separately identifiable, geographic area bounded by wholesale 
metering (e.g., the service territory of an operating company of a Transmission Owner). 
 
Limited Demand Resource: 
 
 
“Limited Demand Resource” shall mean, for Delivery Years through May 31, 2018, and for FRR 
Capacity Plans Delivery Years through May 31, 2019, a resource that is placed under the 
direction of the Office of the Interconnection and that will, at a minimum, be available for 
interruption for at least 10 Load Management Events during the summer period of June through 
September in the Delivery Year, and will be capable of maintaining each such interruption for at 
least a 6-hour duration.  At a minimum, the Limited Demand Resource shall be available for 
such interruptions on weekdays, other than NERC holidays, from 12:00PM (noon) to 8:00PM 
Eastern Prevailing Time.  The Limited Demand Resource must be available during the summer 
period of June through September in the corresponding Delivery Year to be offered for sale or 
Self-Supplied in an RPM Auction, or included as a Limited Demand Resource in an FRR 
Capacity Plan for the corresponding Delivery Year. 
 
Limited Duration Resource: 
 
“Limited Duration Resource” shall mean a Generation Capacity Resource or a generation 
Component DER within a DER Aggregation Resource that is linked to a DER Capacity 
Aggregation Resource, that is not a Variable Resource, that is not a Combination Resource, and 
that is not capable of running continuously at Maximum Facility Output for 24 hours or longer.  
A Capacity Storage Resource is a Limited Duration Resource. 
 
 
Load Serving Entity or LSE: 
 
 
“Load Serving Entity” or “LSE” shall mean any entity (or the duly designated agent of such an 
entity), including a load aggregator or power marketer, (i) serving end-users within the PJM 
Region, and (ii) that has been granted the authority or has an obligation pursuant to state or local 
law, regulation or franchise to sell electric energy to end-users located within the PJM Region.  
Load Serving Entity shall include any end-use customer that qualifies under state rules or a 
utility retail tariff to manage directly its own supply of electric power and energy and use of 
transmission and ancillary services. 
 
 
Locational Reliability Charge:

“Locational Reliability Charge” shall mean the charge determined pursuant to RAA, Article 7, 
section 2. 
 
 
Markets and Reliability Committee: 
 
 
“Markets and Reliability Committee” shall mean the committee established pursuant to the 
Operating Agreement as a Standing Committee of the Members Committee.  
 
 
Maximum Emergency Service Level: 
 
“Maximum Emergency Service Level” or “MESL” of Price Responsive Demand for the 
2017/2018 through the 2021/2022 Delivery Years shall mean the level, determined at a PRD 
Substation level, to which Price Responsive Demand shall be reduced during the Delivery Year 
when a Maximum Generation Emergency is declared and the Locational Marginal Price exceeds 
the price associated with such Price Responsive Demand identified by the PRD Provider in its 
PRD Plan. 
 
Member: 
 
 
“Member” shall have the meaning provided in the Operating Agreement. 
 
 
Members Committee: 
 
 
“Members Committee” shall mean the committee specified in Operating Agreement, section 8 
composed of the representatives of all the Members. 
 
 
NERC: 
 
 
“NERC” shall mean the North American Electric Reliability Corporation or any successor 
thereto. 
 
Network External Designated Transmission Service: 
 
“Network External Designated Transmission Service” shall mean the quantity of network 
transmission service confirmed by PJM for use by a market participant to import power and 
energy from an identified Generation Capacity Resource located outside the PJM Region, upon 
demonstration by such market participant that it owns such Generation Capacity Resource, has 
an executed contract to purchase power and energy from such Generation Capacity Resource, or 
has a contract to purchase power and energy from such Generation Capacity Resource contingent 
upon securing firm transmission service from such resource. 
 
Network Resources: 
 
 
“Network Resources” shall have the meaning set forth in the PJM Tariff.

Network Transmission Service: 
 
 
“Network Transmission Service” shall mean transmission service provided pursuant to the rates, 
terms and conditions set forth in Tariff, Part III or transmission service comparable to such 
service that is provided to a Load Serving Entity that is also a Transmission Owner. 
 
Nominal PRD Value:  
 
“Nominal PRD Value” shall mean, as to any PRD Provider, an adjustment, determined in 
accordance with Reliability Assurance Agreement, Schedule 6.1, to the peak-load forecast used 
to determine the quantity of capacity sought through an RPM Auction, reflecting the aggregate 
effect of Price Responsive Demand on peak load resulting from the Price Responsive Demand to 
be provided by such PRD Provider.    
 
Nominated Demand Resource Value: 
 
 
“Nominated Demand Resource Value” shall have the meaning specified in Tariff, Attachment 
DD. 
 
 
Non-Retail Behind the Meter Generation: 
 
 
“Non-Retail Behind the Meter Generation” shall mean Behind the Meter Generation that is used 
by municipal electric systems, electric cooperatives, and electric distribution companies to serve 
load. 
 
 
Nuclear Class: 
 
“Nuclear Class” shall mean an ELCC Class consisting of Unlimited Resources primarily fueled 
by nuclear fuel. 
 
Obligation Peak Load: 
 
 
“Obligation Peak Load” shall have the meaning specified in Reliability Assurance Agreement, 
Schedule 8. 
 
 
Office of the Interconnection: 
 
 
“Office of the Interconnection” shall mean the employees and agents of PJM Interconnection, 
L.L.C., subject to the supervision and oversight of the PJM Board, acting pursuant to the 
Operating Agreement. 
 
Offshore Wind Class: 
 
“Offshore Wind Class” shall mean an ELCC Class consisting of Variable Resources that produce 
electrical energy with offshore wind turbines located in the ocean.

Onshore Wind Class: 
 
“Onshore Wind Class” shall mean an ELCC Class consisting of Variable Resources that produce 
electrical energy using wind turbines and that are not in the Offshore Wind Class. 
 
 
Operating Agreement of the PJM Interconnection, L.L.C., Operating Agreement or PJM 
Operating Agreement: 
 
 
“Operating Agreement of the PJM Interconnection, L.L.C.,”  “Operating Agreement” or “PJM 
Operating Agreement” shall mean that agreement, dated as of April 1, 1997 and as amended and 
restated as of June 2, 1997, including all Schedules, Exhibits, Appendices, addenda or 
supplements hereto, as amended from time to time thereafter, among the Members of the PJM 
Interconnection, L.L.C, on file with the Commission. 
 
 
Operating Day: 
 
“Operating Day” shall have the same meaning as provided in the Operating Agreement. 
 
 
Operating Reserve: 
 
 
“Operating Reserve” shall mean the amount of generating capacity scheduled to be available for 
a specified period of an Operating Day to ensure the reliable operation of the PJM Region, as 
specified in the PJM Manuals. 
 
Ordinary Water Storage: 
 
“Ordinary Water Storage” shall mean water stored in the pondage or reservoir of a hydropower 
resource which is typically available during normal operating conditions pursuant to the FERC 
license governing the operation of the hydropower resource. 
 
 
Other Limited Duration Class: 
 
“Other Limited Duration Class” shall mean the ELCC Classes specified in RAA Schedules 9.1 
and 9.2 section B of this Agreement, each of which has a specified characteristic duration and 
consists of Limited Duration Resources that are not Capacity Storage Resources. The 
characteristic duration of an Other Limited Duration Class is the maximum period of time 
represented in the ELCC model that the resources of the class can run at a stated capability. 
 
Other Limited Duration Combination Class: 
 
“Other Limited Duration Combination Class” shall mean the ELCC Classes specified in RAA 
Schedules 9.1 and 9.2 section B. Each Other Limited Duration Class has a specified combination 
of two components, whereby, absent being part of a Combination Resource, one component 
would be in an Other Limited Duration Class, and the other component would be in a Variable 
Resource Class or would be an Unlimited Resource. A resource that is a member of an Other 
Limited Duration Combination Class has a single Point Of Interconnection, unless the resource is

controlled in an integrated fashion, is at a single site, and is approved by PJM to be considered a 
single resource in accordance with the PJM Manuals. 
 
Other Supplier: 
 
 
“Other Supplier” shall mean a Member that: (i) is engaged in buying, selling or transmitting 
electric energy, capacity, ancillary services, Financial Transmission Rights or other services 
available under PJM’s governing documents in or through the Interconnection or has a good faith 
intent to do so, and (ii) is not a Generation Owner, Electric Distributor, Transmission Owner or 
End-Use Customer. 
 
 
Other Unlimited Resource Class: 
 
“Other Unlimited Resource Class” shall mean an ELCC Class consisting of Unlimited Resources 
that do not qualify for any other ELCC Class specified in RAA Schedule 9.2, section D. 
 
Other Variable Resource Class: 
 
“Other Variable Resource Class” shall mean an ELCC Class consisting of Variable Resources 
that are not in any other Variable Resource class, including Variable Resources that are 
composed of multiple components, each of which would be a Variable Resource. A resource 
composed of both fixed-tilt solar panels and tracking solar panels is not in this class. A resource 
that is a member of a Other Variable Resource Class has a single Point Of Interconnection, 
unless the resource is controlled in an integrated fashion, is at a single site, and is approved by 
PJM to be considered a single resource in accordance with the PJM Manuals. 
 
Partial Requirements Service: 
 
 
“Partial Requirements Service” shall mean wholesale service to supply a specified portion, but 
not all, of the power needs of a Load Serving Entity to serve end-users within the PJM Region 
that are not satisfied by its own generating facilities. 
 
Party: 
 
“Party” shall mean an entity bound by the terms of the Operating Agreement. 
 
Peak Shaving Adjustment:  
 
“Peak Shaving Adjustment” shall mean a load forecast mechanism that allows load reductions by 
end-use customers to result in a downward adjustment of the summer load forecast for the 
associated Zone. Any End-Use Customer identified in an approved peak shaving plan shall not 
also participate in PJM Markets as Price Responsive Demand, Demand Resource, Base Capacity 
Demand Resource, Capacity Performance Demand Resource, or Economic Load Response 
Participant. 
 
Percentage Internal Resources Required:

“Percentage Internal Resources Required” shall mean, for purposes of an FRR Capacity Plan, the 
percentage of the LDA Reliability Requirement for an LDA that must be satisfied with Capacity 
Resources located in such LDA. 
 
Performance Assessment Interval: 
 
“Performance Assessment Interval” shall have the meaning specified in Tariff, Attachment DD. 
 
 
PJM: 
 
 
“PJM” shall mean PJM Interconnection, L.L.C., including the Office of the Interconnection as 
referenced in the PJM Operating Agreement.  When such term is being used in the RAA it shall 
also include the PJM Board. 
 
 
PJM Board: 
 
 
“PJM Board” shall mean the Board of Managers of the  LLC, acting pursuant to the Operating 
Agreement, except when such term is being used in Tariff, Attachment M, in which case PJM 
Board shall mean the Board of Managers of PJM or its designated representative, exclusive of 
any members of PJM Management. 
 
 
PJM Manuals: 
 
 
“PJM Manuals” shall mean the instructions, rules, procedures and guidelines established by the 
Office of the Interconnection for the operation, planning and accounting requirements of the PJM 
Region. 
 
PJM Region: 
 
 
“PJM Region” shall have the same meaning as provided in the Operating Agreement. 
 
 
PJM Region Installed Reserve Margin: 
 
 
“PJM Region Installed Reserve Margin” shall mean the percent installed reserve margin for the 
PJM Region required pursuant to Reliability Assurance Agreement, Schedule 4.1, as approved 
by the PJM Board. 
 
PJM Tariff, Tariff, O.A.T.T., OATT or PJM Open Access Transmission Tariff: 
 
 
“PJM Tariff,” “Tariff,” “O.A.T.T., “OATT” or “PJM Open Access Transmission Tariff” shall 
mean that certain PJM Open Access Transmission Tariff, including any schedules, appendices, 
or exhibits attached thereto, on file with FERC and as amended from time to time thereafter. 
 
 
Planned Demand Resource:

“Planned Demand Resource” shall mean any Demand Resource that does not currently have the 
capability to provide a reduction in demand or to otherwise control load, but that is scheduled to 
be capable of providing such reduction or control on or before the start of the Delivery Year for 
which such resource is to be committed, as determined in accordance with the requirements of 
Reliability Assurance Agreement, Schedule 6.  As set forth in Reliability Assurance Agreement, 
Schedule 6 and Reliability Assurance Agreement, Schedule 8.1, a Demand Resource Provider 
submitting a DR Sell Offer Plan shall identify as Planned Demand Resources in such plan all 
Demand Resources in excess of those that qualify as Existing Demand Resources. 
 
 
Planned DER Capacity Aggregation Resource: 
 
A “Planned DER Capacity Aggregation Resource” shall mean any DER Capacity Aggregation 
Resource that does not currently have the capability to provide generation or reduction in 
demand, but that is scheduled to be capable of providing such generation or reduction in demand 
on or before the start of the Delivery Year for which such resource is to be committed, as 
determined in accordance with the requirements of Reliability Assurance Agreement, Schedule 
6.2.  As set forth in Reliability Assurance Agreement, Schedule 6.2 and Reliability Assurance 
Agreement, Schedule 8.1, a DER Aggregator submitting a DER Capacity Aggregation Resource 
Sell Offer Plan shall identify in such plan all DER Capacity Aggregation Resources in excess of 
those that qualify as Existing DER Capacity Aggregation Resources.  A Planned DER Capacity 
Aggregation Resource must comply with all provisions of the DER Aggregator Participation 
Model described in Tariff, Attachment K-Appendix, section 1.4B and Operating Agreement, 
Schedule 1, section 1.4B, prior to the applicable Delivery Year. 
 
Planned External Generation Capacity Resource: 
 
 
“Planned External Generation Capacity Resource” shall mean a proposed Generation Capacity 
Resource, or a proposed increase in the capability of a Generation Capacity Resource, that (a) is 
to be located outside the PJM Region, (b) participates in the generation interconnection process 
of a Control Area external to PJM, (c) is scheduled to be physically and electrically 
interconnected to the transmission facilities of such Control Area on or before the first day of the 
Delivery Year for which such resource is to be committed to satisfy the reliability requirements 
of the PJM Region, and (d) is in full commercial operation prior to the first day of such Delivery 
Year, such that it is sufficient to provide the Installed Capacity set forth in the Sell Offer forming 
the basis of such resource’s commitment to the PJM Region.  Prior to participation in any Base 
Residual Auction for such Delivery Year, the Capacity Market Seller must demonstrate that it 
has documentation which is functionally equivalent to an approved Decision Point I submission 
under the PJM Tariff Part VII or VIII as applicable or, for resources which are greater than 
20MWs participating in a Base Residual Auction for the 2019/2020 Delivery Year and 
subsequent Delivery Years, an agreement or other documentation which is functionally 
equivalent to an approved Decision Point II submission under the PJM Tariff Part VII or VIII as 
applicable, with the transmission owner to whose transmission facilities or distribution facilities 
the resource is being directly connected, and, as applicable, the transmission provider.  Prior to 
participating in any Incremental Auction for such Delivery Year, the Capacity Market Seller 
must demonstrate it has entered into an interconnection agreement, or such other documentation 
that is functionally equivalent to a Generation Interconnection Agreement under the PJM Tariff,

with the transmission owner to whose transmission facilities or distribution facilities the resource 
is being directly connected, and, as applicable, the transmission provider.  A Planned External 
Generation Capacity Resource must provide evidence to PJM that it has been studied as a 
Network Resource, or such other similar interconnection product in such external Control Area, 
must provide contractual evidence that it has applied for or purchased transmission service to be 
deliverable to the PJM border, and must provide contractual evidence that it has applied for 
transmission service to be deliverable to the bus at which energy is to delivered, the agreements 
for which must have been executed prior to participation in any Reliability Pricing Model 
Auction for such Delivery Year. Any such resource shall cease to be considered a Planned 
External Generation Capacity Resource as of the earlier of (i) the date that interconnection 
service commences as to such resource; or (ii) the resource has cleared an RPM Auction, in 
which case it shall become an Existing Generation Capacity Resource for purposes of the 
mitigation of offers for any RPM Auction for all subsequent Delivery Years.   
 
 
Planned Generation Capacity Resource: 
 
 
“Planned Generation Capacity Resource” shall mean a Generation Capacity Resource, or 
additional megawatts to increase the size of a Generation Capacity Resource that is being or has 
been modified to increase the number of megawatts of available installed capacity thereof,  
participating in the generation interconnection process under Tariff, Part IV, Subpart A, Part VII 
or Part VIII, as applicable, for which: (i) Interconnection Service is scheduled to commence on 
or before the first day of the Delivery Year for which such resource is to be committed to RPM 
or to an FRR Capacity Plan; (ii) for any such resource seeking to offer into a Base Residual 
Auction, or for any such resource of 20 MWs or less seeking to offer into a Base Residual 
Auction, all the requirements for an approved Decision Point I submission have been met under 
Tariff Part VII or VIII (or, for resources for which a Decision Point I submission is not required, 
has such other agreement or documentation that is functionally equivalent to a an approved 
Decision Point I submission) prior to the Base Residual Auction for such Delivery Year; (iii) for 
any such resource of more than 20 MWs seeking to offer into a Base Residual Auction for the 
2019/2020 Delivery Year and subsequent Delivery Years, all the requirements for an approved 
Decision Point II submission have been met under Tariff Part VII or VIII (or, for resources for 
which a Decision Point II submission is not required, has such other agreement or documentation 
that is functionally equivalent to an approved Decision Point II submission) has been executed 
prior to the Base Residual Auction for such Delivery Year; and (iv) a Generation Interconnection 
Agreement or Wholesale Market Participation Agreement has been executed prior to any 
Incremental Auction for such Delivery Year in which such resource plans to participate.  
Notwithstanding the foregoing, a Planned Generation Capacity Resource shall also include any 
generation resources that are committed through the Reliability Backstop Procurement.  For 
purposes of the must-offer requirement and mitigation of offers for any RPM Auction for a 
Delivery Year, a Generation Capacity Resource shall cease to be considered a Planned 
Generation Capacity Resource as of the earlier of (i) the date that Interconnection Service 
commences as to such resource; or (ii) the resource has cleared an RPM Auction for any 
Delivery Year, in which case it shall become an Existing Generation Capacity Resource for any 
RPM Auction for all subsequent Delivery Years.   
 
 
Planning Period:

“Planning Period” shall mean the 12 months beginning June 1 and extending through May 31 of 
the following year, or such other period approved by the Members Committee. 
 
 
Portfolio Expected Unserved Energy: 
 
“Portfolio Expected Unserved Energy” shall mean the annual amount of expected unserved 
energy, in MWh, that is expected for the RTO when at the annual reliability criteria that provides 
an acceptable level of reliability consistent with the Reliability Principles and Standards. 
 
PRD Curve: 
 
“PRD Curve” shall mean a price-consumption curve at a PRD Substation level, if available, and 
otherwise at a Zonal (or sub-Zonal LDA, if applicable) level, that details the base consumption 
level of Price Responsive Demand and the decreasing consumption levels at increasing prices. 
 
PRD Provider:  
 
“PRD Provider” shall mean a PJM Member that has entered contractual arrangements with end-
use customers that satisfy the eligibility criteria for and provides Price Responsive Demand. 
 
PRD Provider’s Zonal Expected Peak Load Value of PRD:  
 
“PRD Provider’s Zonal Expected Peak Load Value of PRD” shall mean the expected 
contribution to Delivery Year peak load of a PRD Provider’s Price Responsive Demand, were 
such demand not to be reduced in response to price, based on the contribution of the end-use 
customers comprising such Price Responsive Demand to the most recent prior Delivery Year’s 
peak demand, escalated to the Delivery Year in question, as determined in a manner consistent 
with the Office of the Interconnection’s load forecasts used for purposes of the RPM Auctions. 
 
PRD Reservation Price: 
 
“PRD Reservation Price” shall mean an RPM Auction clearing price identified in a PRD Plan for 
Price Responsive Demand load below which the PRD Provider desires not to commit the 
identified load as Price Responsive Demand. 
  
PRD Substation: 
 
“PRD Substation” shall mean an electrical substation that is located in the same Zone or in the 
same sub-Zonal LDA as the end-use customers identified in a PRD Plan or PRD registration and 
that, in terms of the electrical topography of the Transmission Facilities comprising the PJM 
Region, is as close as practicable to such loads. 
 
Price Responsive Demand:

“Price Responsive Demand” or “PRD” shall mean end-use customer load registered by a PRD 
Provider pursuant to Reliability Assurance Agreement, Schedule 6.1 that have, as set forth in 
more detail in the PJM Manuals, the metering capability to record electricity consumption at an 
interval of one hour or less, Supervisory Control capable of curtailing such load (consistent with 
applicable RERRA requirements) at each PRD Substation identified in the relevant PRD Plan or 
PRD registration in response to a Performance Assessment Interval that triggers a PRD 
performance assessment or a Non-PAI Event, and a retail rate structure, or equivalent contractual 
arrangement, capable of changing retail rates as frequently as an hourly basis, that is linked to or 
based upon changes in real-time Locational Marginal Prices at a PRD Substation level and that 
results in a predictable automated response to varying wholesale electricity prices. 
 
Price Responsive Demand Credit: 
 
“Price Responsive Demand Credit” shall mean a credit, based on committed Price Responsive 
Demand, as determined under Reliability Assurance Agreement, Schedule 6.1. 
 
Price Responsive Demand Plan or PRD Plan: 
 
“Price Responsive Demand Plan” or “PRD Plan” shall mean a plan, submitted by a PRD 
Provider and received by the Office of the Interconnection in accordance with Reliability 
Assurance Agreement, Schedule 6.1 and procedures specified in the PJM Manuals, claiming a 
peak demand limitation due to Price Responsive Demand to support the determination of such 
PRD Provider’s Nominal PRD Value. 
 
Public Power Entity: 
 
 
“Public Power Entity” shall mean any agency, authority, or instrumentality of a state or of a 
political subdivision of a state, or any corporation wholly owned by any one or more of the 
foregoing, that is engaged in the generation, transmission, and/or distribution of electric energy. 
 
 
Qualifying Transmission Upgrades: 
 
 
“Qualifying Transmission Upgrades” shall have the meaning specified in Tariff, Attachment DD. 
 
 
Relevant Electric Retail Regulatory Authority: 
 
“Relevant Electric Retail Regulatory Authority” or “RERRA” shall have the meaning specified 
in the PJM Operating Agreement. 
 
Reliability Principles and Standards: 
 
 
“Reliability Principles and Standards” shall mean the principles and standards established by  the 
Office of the Interconnection that define, among other things, an acceptable probabilistic of loss 
of load criteria due to inadequate generation or transmission capability, as amended from time to 
time.

Required Approvals: 
 
 
“Required Approvals” shall mean all of the approvals required for the Operating Agreement to 
be modified or to be terminated, in whole or in part, including the acceptance for filing by FERC 
and every other regulatory authority with jurisdiction over all or any part of the Operating 
Agreement. 
 
 
Self-Supply: 
 
 
“Self-Supply” shall have the meaning provided in Tariff, Attachment DD. 
 
Small Commercial Customer: 
 
“Small Commercial Customer” shall have the same meaning as in the PJM Tariff. 
 
 
State Consumer Advocate: 
 
 
“State Consumer Advocate” shall mean a legislatively created office from any State, all or any 
part of the territory of which is within the PJM Region, and the District of Columbia established, 
inter alia, for the purpose of representing the interests of energy consumers before the utility 
regulatory commissions of such states and the District of Columbia and the FERC.  
 
 
State Regulatory Structural Change: 
 
 
“State Regulatory Structural Change” shall mean as to any Party, a state law, rule, or order that, 
after September 30, 2006, initiates a program that allows retail electric consumers served by such 
Party to choose from among alternative suppliers on a competitive basis, terminates such a 
program, expands such a program to include classes of customers or localities served by such 
Party that were not previously permitted to participate in such a program, or that modifies retail 
electric market structure or market design rules in a manner that materially increases the 
likelihood that a substantial proportion of the customers of such Party that are eligible for retail 
choice under such a program (a) that have not exercised such choice will exercise such choice; or 
(b) that have exercised such choice will no longer exercise such choice, including for example, 
without limitation, mandating divestiture of utility-owned generation or structural changes to 
such Party’s default service rules that materially affect whether retail choice is economically 
viable. 
 
Steam Class: 
 
“Steam Class” shall mean an ELCC Class consisting of Unlimited Resources of the steam 
technology type and the primary fuel is not coal or nuclear. 
 
Summer-Period Demand Resource: 
 
Summer-Period Demand Resource shall mean, for the 2020/2021 Delivery Year and subsequent 
Delivery Years, a resource that is placed under the direction of the Office of the Interconnection,

and will be available June through October and the following May of the Delivery Year, and will 
be available for an unlimited number of interruptions during such months by the Office of the 
Interconnection, and will be capable of maintaining each such interruption between the hours of 
10:00AM to 10:00PM Eastern Prevailing Time.  The Summer-Period Demand Resource must be 
available June through October and the following May in the corresponding Delivery Year to be 
offered for sale in an RPM Auction, or included as a Summer-Period Demand Resource in an 
FRR Capacity Plan for the corresponding Delivery Year. 
 
Summer-Period Energy Efficiency Resource:  
 
Summer-Period Energy Efficiency Resource shall mean, for the 2020/2021 Delivery Year and 
subsequent Delivery Years, a project, including installation of more efficient devices or 
equipment or implementation of more efficient processes or systems, meeting the requirements 
of Reliability Assurance Agreement, Schedule 6 and exceeding then-current building codes, 
appliance standards, or other relevant standards, designed to achieve a continuous (during the 
summer peak periods as described in Reliability Assurance Agreement, Schedule 6 and the PJM 
Manuals) reduction in electric energy consumption that is not reflected in the peak load forecast 
prepared for the Delivery Year for which the Summer-Period Energy Efficiency Resource is 
proposed, and that is fully implemented at all times during such Delivery Year, without any 
requirement of notice, dispatch, or operator intervention. 
 
Supervisory Control: 
 
“Supervisory Control” shall mean the capability to curtail, in accordance with applicable 
RERRA requirements, load registered as Price Responsive Demand at each PRD Substation 
identified in the relevant PRD Plan or PRD registration in response to a Maximum Generation 
Emergency declared by the Office of the Interconnection.  Except to the extent automation is not 
required by the provisions of the Operating Agreement, the curtailment shall be automated, 
meaning that load shall be reduced automatically in response to control signals sent by the PRD 
Provider or its designated agent directly to the control equipment where the load is located 
without the requirement for any action by the end-use customer. 
 
 
Threshold Quantity: 
 
 
“Threshold Quantity” shall mean, as to any FRR Entity for any Delivery Year, the sum of (a) the 
Unforced Capacity equivalent (determined using the Pool-Wide Average EFORD through the 
2024/2025 Delivery Year, or pool-wide average Accredited UCAP Factor effective with the 
2025/2026 Delivery Year) of the Installed Reserve Margin for such Delivery Year multiplied by 
the Preliminary Forecast Peak Load for which such FRR Entity is responsible under its FRR 
Capacity Plan for such Delivery Year, plus (b) the lesser of (i) 3% of the Unforced Capacity 
amount determined in (a) above or (ii) 450 MW.  If the FRR Entity is not responsible for all load 
within a Zone, the Preliminary Forecast Peak Load for such entity shall be determined in 
accordance with Reliability Assurance Agreement, Schedule 8.1, section D.2. 
 
 
Tracking Solar Class:

“Tracking Solar Class” shall mean an ELCC Class consisting of Variable Resources that produce 
electrical energy with solar panels that are primarily mounted on trackers that align the panels 
with incoming sunlight over the course of the day. 
 
Transmission Facilities: 
 
 
“Transmission Facilities” shall mean facilities that:  (i) are within the PJM Region; (ii) meet the 
definition of transmission facilities pursuant to FERC’s Uniform System of Accounts or have 
been classified as transmission facilities in a ruling by FERC addressing such facilities; and (iii) 
have been demonstrated to the satisfaction of the Office of the Interconnection to be integrated 
with the PJM Region transmission system and integrated into the planning and operation of the 
PJM Region to serve all of the power and transmission customers within the PJM Region. 
 
 
Transmission Owner: 
 
 
“Transmission Owner” shall mean a Member that owns or leases with rights equivalent to 
ownership Transmission Facilities and is a signatory to the PJM Transmission Owners 
Agreement.  Taking transmission service shall not be sufficient to qualify a Member as a 
Transmission Owner. 
 
 
Unforced Capacity: 
 
 
“Unforced Capacity” shall mean installed capacity rated at summer conditions that is not on 
average experiencing a forced outage or forced derating, calculated for each Capacity Resource 
on the 12-month period from October to September without regard to the ownership of or the 
contractual rights to the capacity of the unit. 
 
Unlimited Resource: 
 
“Unlimited Resource” shall mean a generating unit having the ability to maintain output at a 
stated capability continuously on a daily basis without interruption.  Through the 2024/2025 
Delivery Year, an Unlimited Resource is a Generation Capacity Resource that is not an ELCC 
Resource. 
 
Variable Resource: 
 
“Variable Resource” shall mean a Generation Capacity Resource or a generation Component 
DER within a DER Aggregation Resource that is linked to a DER Capacity Aggregation 
Resource, with output that can vary as a function of its energy source, such as wind, solar, run of 
river hydroelectric power without storage, and landfill gas units without an alternate fuel source.  
All Intermittent Resources are Variable Resources, with the exception of Hydropower with Non-
Pumped Storage. 
 
 
Winter Peak Load (or WPL):

“Winter Peak Load” or “WPL” shall mean the average of the Demand Resource customer’s 
specific peak hourly load between hours ending 7:00 EPT through 21:00 EPT on the PJM 
defined 5 coincident peak days from December through February two Delivery Years prior the 
Delivery Year for which the registration is submitted.  Notwithstanding, if the average use 
between hours ending 7:00 EPT through 21:00 EPT on a winter 5 coincident peak day is below 
35% of the average hours ending 7:00 EPT through 21:00 EPT over all five of such peak days, 
then up to two such days and corresponding peak demand values may be excluded from the 
calculation.  Upon approval by the Office of the Interconnection, a Curtailment Service Provider 
may provide alternative data to calculate Winter Peak Load, as outlined in the PJM Manuals, 
when there is insufficient hourly load data for the two Delivery Years prior to the relevant 
Delivery Year or if more than two days meet the exclusion criteria described above. 
 
Zonal Capacity Price: 
 
 
“Zonal Capacity Price” shall mean the clearing price required in each Zone to meet the demand 
for Unforced Capacity and satisfy Locational Deliverability Requirements for the LDA or LDAs 
associated with such Zone.  If the Zone contains multiple LDAs with different Capacity 
Resource Clearing Prices, the Zonal Capacity Price shall be a weighted average of the Capacity 
Resource Clearing Prices for such LDAs, weighted by the Unforced Capacity of Capacity 
Resources cleared in each such LDA.   
 
 
Zone or Zonal: 
 
 
“Zone” or “Zonal” shall refer to an area within the PJM Region, as set forth in Tariff, 
Attachment J and RAA, Schedule 15, or as such areas may be (i) combined as a result of mergers 
or acquisitions or (ii) added as a result of the expansion of the boundaries of the PJM Region.  A 
Zone shall include any Non-Zone Network Load located outside the PJM Region that is served 
from such Zone under Tariff, Attachment H-A. 
 
Zonal Winter Weather Adjustment Factor (ZWWAF): 
 
“Zonal Winter Weather Adjustment Factor” or “ZWWAF” shall mean the PJM zonal winter 
weather normalized  coincident peak  divided by PJM zonal average of 5 coincident peak loads 
in December through February.

7.2B 
Responsibility to Pay RBP Charges and Allocation of RBP Shortfall Credits 
 
RBP Charges, which are calculated in accordance with Tariff, Attachment DD, section 
18.5(g)(iii) and RBP shortfall credits that are collected from RBP Sellers pursuant to Tariff, 
Attachment DD, section 18.6(d), are allocated to each Electric Distributor zone/area based on the 
zone/area’s pro rata share of the total Final RBP Target.  To the extent an Electric Distributor has 
notified the Office of the Interconnection of RBP Obligation (“RBO”) MW for each Load 
Serving Entity in its zone/area, as set forth in Tariff, Attachment DD, section 18.3, the Office of 
the Interconnection shall further allocate the RBP Charges, and any RBP shortfall credits, for 
that zone/area to each Party to the RAA, i.e. each Load Serving Entity, in the Electric 
Distributor’s zone/area in accordance with the Electric Distributor’s notification. 
 
To the extent an Electric Distributor has not notified the Office of the Interconnection of the 
RBO MW of each Load Serving Entity in its zone(s)/area(s), the Office of the Interconnection 
shall further allocate the RBP Charges and RBP shortfall charges for that zone/area to each Load 
Serving Entity in the zone/area based on each Load Serving Entity’s share of the Daily Unforced 
Capacity Obligation MW in the zone/area.

7.2C  Provision of RBP Obligations  
 
During the Delivery Year, no later than 36 hours prior to the start of each Operating Day, 
the Electric Distributor shall provide to PJM, for each Party to this Agreement serving load in 
such Electric Distributor's zone/area, any RBP Obligation (“RBO”) MW.  The Electric 
Distributor may submit corrections to the RBO MW data up to 12:00PM Eastern Prevailing 
Time of the next Business Day following the Operating Day.

D. 
FRR Capacity Plans 
 
1. 
Each FRR Entity shall submit its initial FRR Capacity Plan as required by subsection C.1 
of this Schedule, and shall annually extend and update such plan by no later than one month prior 
to the Base Residual Auction for each succeeding Delivery Year in such plan.  Each FRR 
Capacity Plan shall indicate the nature and current status of each resource, including the status of 
each Planned Generation Capacity Resource or Planned Demand Resource, the planned 
deactivation or retirement of any Generation Capacity Resource or Demand Resource, and the 
status of commitments for each sale or purchase of capacity included in such plan. 
 
1.1 
Beginning with the 2020/2021 Delivery Year and for all subsequent Delivery Years, the 
FRR Capacity Plan shall comprise only Capacity Performance Resources and Seasonal Capacity 
Performance Resources.  An FRR Entity may not use an Existing Generation Capacity Resource 
not owned by such FRR Entity as of June 1, 2027 or any resource committed through the 
Reliability Backstop Procurement to satisfy its Capacity FRR Plan. 
 
2. 
The FRR Capacity Plan of each FRR Entity that commits that it will not sell surplus 
Capacity Resources as a Capacity Market Seller in any auction conducted under Attachment DD 
of the PJM Tariff, or to any direct or indirect purchaser that uses such resource as the basis of 
any Sell Offer in such auction, shall designate Capacity Resources in a megawatt quantity no less 
than the Forecast Pool Requirement for each applicable Delivery Year times the FRR Entity’s 
allocated share of the Preliminary Zonal Peak Load Forecast for such Delivery Year, as 
determined in accordance with procedures set forth in the PJM Manuals.  If the FRR Entity is not 
responsible for all load within a Zone, the Preliminary Forecast Peak Load for such entity shall 
be the Base Zonal FRR Scaling Factor times the summation of the FRR Entity’s MW share of 
the Zonal Weather Normalized Summer Peak last determined prior to the Base Residual Auction 
for such Delivery Year plus the Obligation Peak Load MW associated with any Load Adjustment 
specified for such Delivery Year for any “zone/area” served by the FRR Entity’s Capacity Plan.  
The Obligation Peak Load MW associated with a Load Adjustment specified for a “zonal/area” 
is determined as set forth in RAA, Schedule 8, section B. 
 
The FRR Capacity Plan of each FRR Entity that does not commit that it will not sell surplus 
Capacity Resources as set forth above shall designate Capacity Resources at least equal to the 
Threshold Quantity.  To the extent the FRR Entity’s allocated share of the Final Zonal Peak 
Load Forecast exceeds the FRR Entity’s allocated share of the Preliminary Zonal Peak Load 
Forecast, such FRR Entity’s FRR Capacity Plan shall be updated to designate additional 
Capacity Resources in an amount no less than the Forecast Pool Requirement times such 
increase; provided, however, any excess megawatts of Capacity Resources included in such FRR 
Entity’s previously designated Threshold Quantity, if any, may be used to satisfy the capacity 
obligation for such increased load.  To the extent the FRR Entity’s allocated share of the Final 
Zonal Peak Load Forecast is less than the FRR Entity’s allocated share of the Preliminary Zonal 
Peak Load Forecast, such FRR Entity’s FRR Capacity Plan may be updated to release previously 
designated Capacity Resources in an amount no greater than the Forecast Pool Requirement 
times such decrease.  Peak load values referenced in this section shall be adjusted as necessary to 
take into account any applicable Nominal PRD Values approved pursuant to Schedule 6.1 of this 
Agreement.  Any FRR Entity seeking an adjustment to peak load for Price Responsive Demand

must submit a separate PRD Plan in compliance with Section 6.1 (provided that the FRR Entity 
shall not specify any PRD Reservation Price), and shall register all PRD-eligible load needed to 
satisfy its PRD commitment and be subject to compliance charges as set forth in that Schedule 
under the circumstances specified therein; provided that for non-compliance by an FRR Entity, 
the compliance charge rate shall be equal to 1.20 times the Capacity Resource Clearing Price 
resulting from all RPM Auctions for such Delivery Year for the LDA encompassing the FRR 
Entity’s Zone, weight-averaged for the Delivery Year based on the prices established and 
quantities cleared in the RPM auctions for such Delivery Year; and provided further that an 
alternative PRD Provider may provide PRD in an FRR Service Area by agreement with the FRR 
Entity responsible for the load in such FRR Service Area, subject to the same terms and 
conditions as if the FRR Entity had provided the PRD. 
 
3. 
As to any FRR Entity, the Base Zonal FRR Scaling Factor for each Zone in which it 
serves load for a Delivery Year shall equal [(ZPLDY-ZLA) / ZWNSP], where: 
 
ZPLDY = Preliminary Zonal Peak Load Forecast for such Zone for such Delivery Year;  
 
ZLA = the Zonal MW quantity of Load Adjustment for such Delivery Year; and  
 
ZWNSP = Zonal Weather-Normalized Summer Peak Load for such Zone for the summer 
concluding four years prior to the commencement of such Delivery Year. 
 
4. 
Capacity Resources identified and committed in an FRR Capacity Plan shall meet all 
requirements under this Agreement, the PJM Tariff, and the PJM Operating Agreement 
applicable to Capacity Resources, including, as applicable, requirements and milestones for 
Planned Generation Capacity Resources and Planned Demand Resources.  A Capacity Resource 
submitted in an FRR Capacity Plan must be on a unit-specific basis, and may not include “slice 
of system” or similar agreements that are not unit specific.  An FRR Capacity Plan may include 
bilateral transactions that commit capacity for less than a full Delivery Year only if the resources 
included in such plan in the aggregate satisfy all obligations for all Delivery Years.  All demand 
response, load management, energy efficiency, or similar programs on which such FRR Entity 
intends to rely for a Delivery Year must be included in the FRR Capacity Plan, subject to 
applicable demand resource constraints for the relevant Delivery Year, submitted three years in 
advance of such Delivery Year and must satisfy all requirements applicable to Demand 
Resources or Energy Efficiency Resources, as applicable, including, without limitation, those set 
forth in Schedule 6 to this Agreement and the PJM Manuals; provided, however, that previously 
uncommitted Unforced Capacity from such programs may be used to satisfy any increased 
capacity obligation for such FRR Entity resulting from a Final Zonal Peak Load Forecast 
applicable to such FRR Entity.  Without limiting the generality of the foregoing, the FRR Entity 
must submit a Demand Resource Sell Offer Plan 15 business days before the deadline for 
submitting an FRR Capacity Plan as to any Demand Resources it intends to include in such FRR 
Capacity Plan and may only include in such FRR Capacity Plan Demand Resources that are 
approved by PJM following review of such Demand Resource Sell Offer Plan.  The 
requirements, standards, and procedures for a Demand Resource Sell Offer Plan shall be as set 
forth in Schedule 6 of this Agreement, provided that all references (including deadlines) in 
Schedule 6, section A-1 to submission or clearing of a Demand Resource offer in an RPM

Auction shall be understood for purposes of FRR Entities as referring to inclusion of a Demand 
Resource in an FRR Capacity Plan, and a distinct Demand Resource Officer Certification Form 
shall be applicable to FRR Entities, as shown in the PJM Manuals and provided on the PJM 
website. 
 
5. 
For each LDA for which the Office of the Interconnection is required to establish a 
separate Variable Resource Requirement Curve for any Delivery Year addressed by such FRR 
Capacity Plan, the plan must include a Percentage Internal Resources Required, subject to 
subsections D.1.1 and D.2 of this Schedule.  The Percentage Internal Resources Required will be 
calculated as the LDA Reliability Requirement less the CETL for the Delivery Year, as 
determined by the RTEP process as set forth in the PJM Manuals.  Such requirement shall be 
expressed as a percentage of the Unforced Capacity Obligation based on the Preliminary Zonal 
Peak Load Forecast multiplied by the Forecast Pool Requirement.  Notwithstanding the 
provisions of Sections C.1 and C.2 of this Schedule 8.1, an FRR Entity may terminate its 
election of the FRR Alternative prior to meeting its minimum five year commitment 
without penalty for any Delivery Year after the first Delivery Year of its minimum five 
year FRR commitment for which the Office of the Interconnection will be required to 
establish a separate Variable Resource Requirement Curve by giving written notice two 
months prior to the Base Residual Auction for the Delivery Year. The Office of the 
Interconnection shall be deemed to be required to establish a separate Variable Resource 
Requirement Curve for an LDA if the LDA is the Eastern Mid-Atlantic Region 
(“EMAR”), Southwest Mid-Atlantic Region (“SWMAR”), or Mid-Atlantic Region 
(“MAR”), or for other LDAs if the separate modeling is required by Section 
5.10(a)(ii)(A) or (B) of Attachment DD of the Tariff. 
 
6. 
An FRR Entity may reduce the Percentage Internal Resources Required as to any LDA to 
the extent the FRR Entity commits to a transmission upgrade that increases the CETL for such 
LDA.  Any such transmission upgrade shall adhere to all requirements for a Qualified 
Transmission Upgrade as set forth in Attachment DD to the PJM Tariff.  The increase in CETL 
used in the FRR Capacity Plan shall be that approved by PJM prior to inclusion of any such 
upgrade in an FRR Capacity Plan.  The FRR Entity shall designate specific additional Capacity 
Resources located in the LDA from which the CETL was increased, to the extent of such 
increase. 
 
7. 
The Office of the Interconnection will review the adequacy of all submittals hereunder 
both as to timing and content.  A Party that seeks to elect the FRR Alternative that submits an 
FRR Capacity Plan which, upon review by the Office of the Interconnection, is determined not to 
satisfy such Party’s capacity obligations hereunder, shall not be permitted to elect the FRR 
Alternative.  If a previously approved FRR Entity submits an FRR Capacity Plan that, upon 
review by the Office of the Interconnection, is determined not to satisfy such Party’s capacity 
obligations hereunder, the Office of the Interconnection shall notify the FRR Entity, in writing, 
of the insufficiency within five (5) business days after the submittal deadline of the FRR 
Capacity Plan.  Through the 2024/2025 Delivery Year, if the FRR Entity does not cure such 
insufficiency within five (5) business days after receiving such notice of insufficiency, then such 
FRR Entity shall be assessed an FRR Commitment Insufficiency Charge, in an amount equal to 
two times the Cost of New Entry for the relevant location, in $/MW-day, times the shortfall of

Capacity Resources below the FRR Entity’s capacity obligation (including any Threshold 
Quantity requirement) in such FRR Capacity Plan, for the remaining term of such plan. For 
Delivery Years between the 2025/2026 Delivery Year through the 2028/2029 Delivery Year, no 
FRR Commitment Insufficiency Charge shall be assessed. Effective with the 2029/2030 Delivery 
Year and subsequent Delivery Years, if the FRR Entity does not cure such insufficiency within 
five (5) business days after receiving such notice of insufficiency, then such FRR Entity shall be 
assessed an FRR Commitment Insufficiency Charge, in an amount equal to the price level 
corresponding to point (1) of the Variable Resource Requirement curve, as provided in Tariff, 
Attachment DD, section 5.10(a)(i), for the relevant Locational Deliverability Area, in $/MW-
day, times the shortfall of Capacity Resources below the FRR Entity’s capacity obligation 
(including any Threshold Quantity requirement) in such FRR Capacity Plan, for such Delivery 
Year.  
 
8. 
In a state regulatory jurisdiction that has implemented retail choice, the FRR Entity must 
include in its FRR Capacity Plan all load, including expected load growth, in the FRR Service 
Area, notwithstanding the loss of any such load to or among alternative retail LSEs.  In the case 
of load reflected in the FRR Capacity Plan that switches to an alternative retail LSE, where the 
state regulatory jurisdiction requires switching customers or the LSE to compensate the FRR 
Entity for its FRR capacity obligations, such state compensation mechanism will prevail.  In the 
absence of a state compensation mechanism, the applicable alternative retail LSE shall 
compensate the FRR Entity at the capacity price in the unconstrained portions of the PJM 
Region, as determined in accordance with Attachment DD to the PJM Tariff, provided that the 
FRR Entity may, at any time, make a filing with FERC under Sections 205 of the Federal Power 
Act proposing to change the basis for compensation to a method based on the FRR Entity's cost 
or such other basis shown to be just and reasonable, and a retail LSE may at any time exercise its 
rights under Section 206 of the FPA. 
 
9. 
Notwithstanding the foregoing, in lieu of providing the compensation described above, 
such alternative retail LSE may, for any Delivery Year subsequent to those addressed in the FRR 
Entity’s then-current FRR Capacity Plan, provide to the FRR Entity Capacity Resources 
sufficient to meet the capacity obligation described in paragraph D.2 for the switched load. Such 
Capacity Resources shall meet all requirements applicable to Capacity Resources pursuant to this 
Agreement, the PJM Tariff, and the PJM Operating Agreement, all requirements applicable to 
resources committed to an FRR Capacity Plan under this Agreement, and shall be committed to 
service to the switched load under the FRR Capacity Plan of such FRR Entity.  The alternative 
retail LSE shall provide the FRR Entity all information needed to fulfill these requirements and 
permit the resource to be included in the FRR Capacity Plan.  The alternative retail LSE, rather 
than the FRR Entity, shall be responsible for any performance charges or compliance penalties 
related to the performance of the resources committed by such LSE to the switched load.  For 
any Delivery Year, or portion thereof, the foregoing obligations apply to the alternative retail 
LSE serving the load during such time period.  PJM shall manage the transfer accounting 
associated with such compensation and shall administer the collection and payment of amounts 
pursuant to the compensation mechanism.

Such load shall remain under the FRR Capacity Plan until the effective date of any termination 
of the FRR Alternative and, for such period, shall not be subject to Locational Reliability 
Charges under Section 7.2 of this Agreement.